Attached files

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EX-21.1 - LIST OF SUBSIDIARIES - SKY PETROLEUM, INC.ex21_1.htm
EX-31.2 - CERTIFICATION OF CHIEF FINANCIAL OFFICER - SKY PETROLEUM, INC.ex32_2.htm
EX-31.2 - CERTIFICATION OF CHIEF FINANCIAL OFFICER - SKY PETROLEUM, INC.ex31_2.htm
EX-31.1 - CERTIFICATION OF CHIEF EXECUTIVE OFFICER - SKY PETROLEUM, INC.ex31_1.htm
EX-32.1 - CERTIFICATION OF CHIEF EXECUTIVE OFFICER - SKY PETROLEUM, INC.ex32_1.htm
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K

x
 
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2010
 
OR
     
o
 
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the transition period from            to
 
Commission file number: 333-99455
 
 
 
SKY PETROLEUM, INC.

(Exact Name of Registrant as Specified in its Charter)
 
 
 
Nevada
 
32-0027992
(State of other jurisdiction of incorporation or organization)
 
(I.R.S. Employer Identification No.)
     
401 Congress Avenue, Suite 1540
   
Austin, Texas
 
78701
(Address of Principal Executive Offices)
 
(Zip Code)
  
(512) 687-3427

(Registrant’s Telephone Number, including Area Code)

SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT: None

SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: Common Stock, $0.001 par value

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No x
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No x
 
Indicate by check mark whether the registrant (1) 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 xNo o
 
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o No o
 
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 the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to the Form 10-K o
  
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act (Check one):
 
 
 Large Accelerated Filer       o  Non-Accelerated Filer        o  Accelerated Filer    o  Smaller Reporting Company         x
       
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o No x

State the aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed fourth fiscal quarter: $27,222,322

The number of shares of the Registrant’s Common Stock outstanding as of March 25, 2011 was 61,868,709.

 
 
 

 

 
TABLE OF CONTENTS
 
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS
  1

PART I
  2

ITEM 1. BUSINESS
  2

ITEM 1A. RISK FACTORS
  9

ITEM 1B. UNRESOLVED STAFF COMMENTS
15

ITEM 2. PROPERTIES
15

ITEM 3. LEGAL PROCEEDINGS
15

ITEM 4. [REMOVED AND RESERVED]
16

PART II
16

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
16

ITEM 6. SELECTED FINANCIAL DATA
18

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
18

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
29

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
30

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
49

ITEM 9A CONTROLS AND PROCEDURES
49

ITEM 9B. OTHER INFORMATION
50

PART III
51

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE
 
51
ITEM 11. EXECUTIVE COMPENSATION
55

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDERS MATTERS
58

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
58

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
59

PART IV
60

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
60

SIGNATURES
61


 
 

 

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K and the exhibits attached hereto contain certain statements that constitute “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. Such forward-looking statements concern our anticipated results and developments in our operations in future periods, planned exploration and development of our properties, plans related to our business and matters that may occur in the future. These statements relate to analyses and other information that are based on forecasts of future results, estimates of amounts not yet determinable and assumptions of management.

Any statements that express or involve discussions with respect to predictions, expectations, beliefs, plans, projections, objectives, assumptions or future events or performance (often, but not always, using words or phrases such as “expects” or “does not expect”, “is expected”, “anticipates” or “does not anticipate”, “plans”, “estimates” or “intends”, or stating that certain actions, events or results “may”, “could”, “would”, “might” or “will” be taken, occur or be achieved) are not statements of historical fact and may be forward-looking statements. Forward-looking statements are subject to a variety of known and unknown risks, uncertainties and other factors which could cause actual events or results to differ from those expressed or implied by the forward-looking statements, including, without limitation:

risks related to our limited operating history;

risks related to our properties and proposed operations in Albania;

risks related to our ability to perform under the terms of our production sharing contract;

risks related to government regulations and approvals in the countries in which we operate;

risks and uncertainty related to our legal rights under the participation agreement for the Mubarek Field;

risks related to our financing and development activities;

risks related to the historical losses and expected losses in the future;

risks related to our dependence on our executive officers;

risks related to fluctuations in oil and natural gas prices;

risks related to exploratory activities, drilling for and producing oil and natural gas;

risks related to liability claims from oil and gas operations;

risks related to accessing the oil and natural gas markets;

risks related to legal compliance costs;

risks related to the unavailability of drilling equipment and supplies;

risks related to competition in the oil and natural gas industry;

risks related to period to period comparison of our financial results;

risks related to our securities;

risks related to our ability to raise capital or enter into joint venture or working interest arrangements on acceptable terms; and

political, social and cultural risks associated with operations and conducting business in foreign countries.

This list is not exhaustive of the factors that may affect our forward-looking statements. Some of the important risks and uncertainties that could affect forward-looking statements are described further under the sections titled “Risk Factors”, “Business” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Annual Report. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results may vary materially from those anticipated, believed, estimated or expected. Our management has included projections and estimates in this Annual Report, which are based primarily on management’s experience in the industry, assessments of our results of operations, discussions and negotiations with third parties and a review of information filed by our competitors with the Securities and Exchange Commission
 
 
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(which we refer to as the “SEC”) or otherwise publicly available. We caution readers not to place undue reliance on any such forward-looking statements, which speak only as of the date made. We disclaim any obligation subsequently to revise any forward-looking statements to reflect events or circumstances after the date of such statements or to reflect the occurrence of anticipated or unanticipated events, except as required by law.

We qualify all the forward-looking statements contained in this Annual Report by the foregoing cautionary statements.

PART I
 
As used herein, the terms, “Sky Petroleum,” “Sky,” “the Company,” “we,” “us,” and “our” refer to Sky Petroleum, Inc.

ITEM 1. BUSINESS
 
Overview

Our primary business is to identify opportunities to either make direct property acquisitions or to fund exploration or development of oil and natural gas properties of others under arrangements in which we will finance the costs in exchange for interests in the oil or natural gas revenue generated by the properties. Such arrangements are commonly referred to as farm-ins to us, or farm-outs by the property owners farming out to us.
 
On June 24, 2010, Sky entered into a Production Sharing Contract (“PSC”) with the Ministry of Economy, Trade and Energy of Albania, acting through the National Agency of Natural Resources of Albania (“AKBN”). An official copy of the document evidencing approval by the Council of Ministers of the Republic of Albania of the PSC was published in the Fletoren Zyrtare on December 17, 2010, and the PSC became effective ten working days thereafter on January 3, 2011. The PSC grants Sky Petroleum exclusive rights to three exploration blocks (Block Four, Block Five and Block Dumre) in the Republic of Albania (the “Concession Area”). The Concession Area covers approximately 1.2 million acres, representing approximately 20% of the landmass of Albania. The PSC has a seven-year term with three exploration periods. Upon commercial discovery of gas, the agreement allows for development and production periods of 25 years plus extensions at the Company’s option. To date, there have been more than ten identified prospects including three significant evaluation wells in each block: Palokastra well in Block Four, Kanina well in Block Five, and a Dumre well in Block Dumre.

On May 18, 2005, the Company, through its wholly-owned subsidiary Sastaro Limited (“Sastaro”), entered into a Participation Agreement with Buttes Gas and Oil Co. International Inc. (which we refer to as “Buttes”), a wholly-owned subsidiary of Crescent Petroleum Company International Limited (which we refer to as “Crescent”) for the financing of a drilling program (the “Participation Agreement”). The project is located in the Ilam/Mishrif reservoir of the Mubarek Field area near Abu Musa Island in the Arabian Gulf. Under the terms of the Participation Agreement, the Company participated in a share of the future production revenue by contributing $25 million in drilling and completion costs related to two in-fill wells in an off-shore oil and gas project in the United Arab Emirates. The operator of the drilling program, Crescent, secured a drilling rig and began drilling the first well, Mubarek H2, which was completed during the second quarter of 2006 at a total depth of 15,020 feet (drilled depth). The second well Mubarek K2-ST4 was completed on October 4, 2007, with a total depth of 13,533 feet. Since the Mubarek H2 well was completed it has produced a total of 150,413 gross barrels of oil as of December 31, 2010. Since the Mubarek K2-ST4 well was completed, it has produced a total of 149,471 gross barrels of oil as of December 31, 2010.

On December 31, 2009, the Company received written notice from Buttes that Buttes unilaterally and solely determined that the Mubarek Field had reached the end of its economic life. Buttes also notified Sastaro that the Concession Agreement, dated December 29, 1969, between the His Highness Sheikh Sultan bin Mohamed Al-Qassimi III, The Ruler of Sharjah, UAE and Buttes with respect to the Mubarek Field (the “Concession Agreement”) was terminated. Buttes have stated that it handed over the Mubarek Field operations and facilities to representatives of His Highness Sheikh Sultan bin Mohamed Al-Qassimi III on December 28, 2009. Management is exercising its rights under the Participation Agreement and intends to take all actions required to protect our interests, our shareholders and our investment in the Mubarek Field.

History and Corporate Structure

We were incorporated in the state of Nevada in August 2002 as The Flower Valet. In 2004, we began to reassess our business plan and to seek business opportunities in other industries, including the oil and gas industry. On December 20, 2004, at our annual meeting of stockholders, our stockholders approved an amendment to our Articles of Incorporation, changing our name from The Flower Valet to Seaside Exploration, Inc. Subsequently, on March 28, 2005, we changed our name from Seaside Exploration, Inc. to Sky Petroleum, Inc. and began actively identifying opportunities to make direct property acquisitions and to fund exploration and development of oil and natural gas properties.
 
 
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On March 28, 2005, we increased our authorized capital from 100,000,000 shares of common stock, $0.001 par value per share, to 150,000,000 shares of common stock, $0.001 par value per share. On March 28, 2005, we affected a 4 for 1 forward stock-split of our issued and outstanding shares of common stock, increasing the number of shares of common stock outstanding from 6,500,000 to 26,000,000 shares. Information contained in this Annual Report gives effect to the forward split. We also authorized 10,000,000 shares of Preferred Stock Series A, $0.001 par value per share. On April 20, 2007, all 3,055,556 shares of Series A Preferred Stock outstanding were converted into 12,222,224 shares of our common stock.

On October 8, 2010, the Company filed a Certificate of Designation with the Secretary of State for the State of Nevada to designate 5,000,000 shares of the Company’s preferred stock as shares of Series B Preferred Stock (the "Series B Preferred Shares").  The Company issued 3,863,636 Series B Preferred Shares to a consultant (“the Consultant”) under the terms of a consultant agreement related to the final approval of the PSC.

As of December 31, 2010, the Company had two wholly-owned subsidiaries incorporated in Cyprus: Sastaro Limited (which we refer to as “Sastaro”) and Bekata Limited (which we refer to as “Bekata”) which owns 100% of Sastaro.
 
SKY PETROLEUM, INC.
ORGANIZATION STRUCTURE

Sastaro was incorporated on March 28, 2005. Bekata was incorporated on February 7, 2005.

On February 17, 2011, we incorporated Sky Petroleum (Albania) Inc., a Cayman Islands corporation and qualified branch in Albania, for the purposes of holding and operating our interests in the Concession Area in Albania. Sky Petroleum (Albania) Inc. is a wholly-owned subsidiary of Sky Petroleum, Inc.

Our principal corporate and executive offices are located at 401 Congress Avenue, Suite 1540, Austin, Texas 78701. Our telephone number is (512) 687-3427. We maintain a website at www.skypetroleum.com. Information contained on our website is not part of this Annual Report.
 
Production Sharing Contract with the Ministry of Economy, Trade and Energy of Albania:

On June 24, 2010, Sky was granted exclusive rights under a Production Sharing Contract to three exploration blocks totaling approximately 5,000 km2 (1.2 million acres), representing approximately 20% of the landmass of Albania. In addition to the exploration rights, the company will also have access to more than 1,200 km of 2-D seismic data. The PSC has a seven-year term with three exploration periods. Upon commercial discovery of gas, the agreement allows for development and production periods of 25 years plus extensions at the Company’s option.

The PSC grants Sky Petroleum exclusive rights to three exploration blocks (Block Four, Block Five and Block Dumre) in the Republic of Albania (the “Concession Area”).

Block Four is located in southeast Albania, bordering Greece. The exploration block covers an area of approximately 2,264 km2 (540,000 acres). The area has four identified leads and prospects on the block with a total estimated reserve potential of 350 million barrels of oil equivalent (“MMBOE”).

Block Five is located in southwest Albania next to the Adriatic Sea and covers an area of approximately 2,076 km2 (498,000 acres). The block has a total of five identified prospects or leads with a total estimated reserve potential of 375 MMBOE.

Block Dumre is located immediately north of the Kucova oil field and covers an area of approximately 623 km2 (149,000 acres). Based on analogous discoveries, it is estimated that the Dumre prospect contains approximately 500 to 700 MMBOE original oil in place (“OOIP”).
 
 
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Sky received final approval and ratification for the Production Sharing Contract with respect to the three exploration blocks, Four, Five and Dumre. The PSC received regulatory approval from the Council of Ministers of the Government of the Republic of Albania on November 25, 2010.  On December 17, 2010, a copy of the document evidencing final approval of the Council of Ministers of the Republic of Albania was published in the Fletoren Zyrtare.  The PSC became effective 10 working days after publication of the document on January 3, 2011.

On September 23, 2010, Sky released the findings of a detailed report written in cooperation with McKinsey & Company, one of the world’s leading consulting firms, assessing the potential value of the three exploration blocks, Four, Five and Dumre (the “Albanian Blocks”). The report estimates the Albanian Blocks:

contain a mean un-risked reserve potential of 875 MMBOE;

with a conservative average success rate of approximately 24%, which would translate to a mean risked reserve potential of 220 MMBOE;

have a potential market value of between $1 billion to $3 billion based on expected P90 reserves of approximately 105 MMBOE at $10 to $30 per barrel of oil equivalent (BOE); and

possess a mean net present value of about $2.1 billion based on a stochastic discounted cash flow valuation of their likely commercialization.

According to the findings, which are based on previous reserve estimates, there are significant reserves contained in the Albanian Blocks. Each block has promising prospects with existing data, including seismic and well logs. The National Agency of Natural Resources of Albania (“AKBN”) provided the Company and its consultant access to previous reserves studies including one prepared by OMV, Austria’s largest oil-producing, refining and retail operating company.

The McKinsey Report was not prepared in compliance with SEC Guide 2 standards for oil and gas reserves and only reports reserve potential.   You should not place undue reliance on the McKinsey Report.

About the Republic of Albania

Albania has a population of 3.5 million people and is located 50 km east of Italy, across the Adriatic Sea in Southeast Europe. Albania is a member of NATO, and has applied to join the European Union. Albania is a proven hydrocarbon producing region with earliest known bitumen production dating back to the Roman Empire. Modern exploration began in the early 1900s. The Patmos – Marinza and Kucova heavy oilfields are among the largest oilfields in Europe. To date there have been ten significant field discoveries that have produced more than 150 million barrels.

Exploration Periods

First Exploration Period: The first exploration period is an initial period of two years in which Sky Petroleum has agreed to undertake G&G, including but not limited to acquisition of technical data, interpretation of geological, geophysical and well data, and conducting regional geological and structural studies (mapping, balanced cross sections); seismic reprocessing and seismic acquisition, with minimum expenditure commitments totaling $1,500,000.

Second Exploration Period:  Provided that Sky Petroleum has completed the minimum first exploration period work program or paid AKBN the minimum expenditure amount, Sky Petroleum may elect to extend the exploration period into a second exploration period of three years.  During the second exploration period, Sky Petroleum will undertake G&G; seismic acquisition and an exploration drilling program with minimum expenditure commitments totaling $2,650,000.

At the end of the first or second exploration period, Sky Petroleum shall have the right, subject to AKBN approval, to extend such periods by one year, reducing the later periods by one year.

Third Exploration Period:  Provided that Sky Petroleum has completed the minimum second exploration period work program or paid AKBN the minimum expenditure amount, if, as approved by the AKBN, there are special circumstances which require more time for the contractor to perform adequate exploration activity, Sky Petroleum may elect to extend the exploration period into a third exploration period of two years.  During the third exploration period, Sky Petroleum will undertake G&G; seismic acquisition and an exploration drilling program with minimum expenditure commitments totaling $3,150,000.

If during the exploration periods, Sky Petroleum discovers petroleum accumulations capable of commercial production within the Concession Area (a “Discovery Area”); it can submit to AKBN a development plan and commence development of the Discovery Area.  Sky Petroleum will have production rights of 25 years for each field (a “Production Area”) from the date of initial commercial
 
 
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production, which may be extended, at Sky Petroleum’s option, for successive periods of five years on the same conditions, subject to approval by AKBN, which approval shall not be unreasonably withheld or delayed.  Sky Petroleum and AKBN will share profits from any commercial production of oil (after cost recovery by Sky Petroleum) based on a sliding scale formula, in which Sky Petroleum’s share of profits will range from 96% to 100%.  All available production is subject to a 10% royalty tax and Sky Petroleum’s profits are subject to a 50% Albania tax on petroleum profits.

Sky Petroleum will relinquish to AKBN 25% of the Concession Area, as designated by Sky Petroleum, within 180 days after the end of each of the First Exploration Period and the Second Exploration Period and all remaining acreage of the Concession Area at the end of the Third Exploration Period, that is not then subject to a Discovery Area or in a Production Area.  Sky Petroleum will not be required to relinquish areas included in a Discovery Area or in Production Area.

Sky Petroleum or an affiliated entity designated by Sky Petroleum will serve as operator under the Agreement. Sky Petroleum intends to use affiliated entities to hold and operate the Concession Area. Sky Petroleum organized a Cayman Island corporation to hold and operate the Concession Areas.

The Company’s investment in the Albania exploration blocks as of December 31, 2010 was $10,115,220.  This investment consisted of acquisition costs related to the PSC totaling $50,000, $850,000 for fees to consultants for locating and negotiating our investment in the Albania exploration blocks, and $225,220 for fees related to evaluations and assessments of the concession area.  In addition, 3 million shares of common stock with a fair value of $1,170,000, plus 3,863,636 Preferred Shares Series B with a value of $7,820,000, were issued to the Consultant for expertise provided to the Company in acquiring and negotiating the acquisition of oil and gas properties in Albania.

Mubarek Field - Participation Agreement:

On May 18, 2005, we announced that our wholly-owned subsidiary, Sastaro, entered into a Participation Agreement with Buttes Under the terms of the Participation Agreement, Sastaro has the right to participate in a share of the future production revenue by contributing up to $25 million in drilling and completion costs related to two wells in an off-shore oil and gas project in the United Arab Emirates. The project is located in the Ilam/Mishrif reservoir of the Mubarek Field area near Abu Musa Island in the Arabian Gulf, which we refer to as the “Mubarek Concession Area”. The Participation Agreement does not grant Sastaro any interest in the Mubarek Concession Area other than the right to receive a share of future production revenue.
 
The Participation Agreement obligated Sastaro to pay $25 million in drilling and completion costs related to two wells. As of March 31, 2006, Sastaro had paid Buttes the full $25 million commitment. Buttes have the responsibility for carrying out all drilling and completion work related to the wells.
 
Under the Participation Agreement, if Buttes estimated that the drilling and completion costs of the second well increased the total drilling and completion costs of the two wells above $25 million, Sastaro would have the option, but not the obligation, to pay these additional costs. Upon exercising this option, Sastaro would become obligated to pay the total costs of the second well whether above or below Buttes’ estimate. As of December 31, 2008, Buttes reported that the drilling and completion costs for the Mubarek H2 and K2-ST4 wells totaled approximately $53 million. Sastaro did not exercise the option to pay the additional costs in completion of the first 2 wells.
 
In exchange for the payment obligations described above, Sastaro receives:
 
35.25% of the combined production revenue from the wells, if any, until Sastaro has been reimbursed its total investment;
 
thereafter, 18.84% of the combined production revenue from the wells, if any, until Sastaro has been reimbursed twice its total investment; and
 
thereafter, 4.33% of the combined production revenue from the wells, if any, until the expiration of the Participation Agreement; and
 
less: (i) a 14.5% contribution to royalty obligations, (ii) $3 per barrel of crude oil for operating costs and (iii) certain other costs.
 
In December 2009, we received written notice from Crescent, the operator of the Mubarek Field, through its wholly owned subsidiary Buttes that Buttes had unilaterally and solely determined that the Mubarek Field had reached the end of its economic life. Accordingly, the Concession Agreement, dated December 29, 1969, between the His Highness Sheikh Sultan bin Mohamed Al-Qassimi III, The Ruler of Sharjah, UAE and Buttes with respect to the Mubarek Field (which we refer to as the “Concession Agreement”) was terminated. Buttes have stated that it had handed over the Mubarek Field operations and facilities to representatives of His Highness Sheikh Sultan bin Mohamed Al-Qassimi III on December 28, 2009.
 
 
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As a result of these events, Buttes alleges that the Participation Agreement between Sastaro and Buttes is terminated. We strongly disagree with Crescent and Butte’s assessment of the economic viability of the Mubarek Field. The Mubarek Field continued to produce substantial amounts of oil at termination and we believe that there is significant economic life left in the field. Consequently, we consider the Participation Agreement valid and in good standing. Management intends to exercise all of Sky’s rights under the Participation Agreement and will take any and all actions required to protect our interests, our shareholders and our investment in the Mubarek Field.

Mubarek Field Program
 
We retained Energy Services Group of Dubai (which we refer to as “ESG”) to provide a technical review of the project in the Mubarek Field area near Abu Musa Island in the Arabian Gulf based on an evaluation of data provided to us by Buttes. Ian Baron, a former director of the Company, who was appointed in November 2005 and resigned in May 2008, is a founding partner of ESG. The review, based on information contained in ESG’s report, included geological, geophysical and reservoir engineering re-interpretation and analysis. The objective of the review was to select those well locations with the highest productive oil potential. The major influences on determining this included the following:
 
position on structure
 
potential net pay
 
well productivity
 
water-cut
  
The Mubarek Field was discovered in 1972 and is located in about 200 feet of water 12 kilometers from Abu Musa Island offshore Sharjah, UAE. The field is a large anticlinal structure with about 600 feet of vertical relief and with dimensions of approximately 15 by 11 kilometers. Hydrocarbons were encountered in the Cretaceous Ilam, Mishrif and Thamama reservoirs. Only the Ilam / Mishrif reservoirs are involved in this in-fill drilling project.

Of the well locations reviewed, two locations, H2 and K2 ST4 were selected as being most attractive for potential oil production.
 
Approximately 86 million barrels have been produced putting recovery somewhere between 20% and 30%. Given the recovery to date, the distribution of the wells and the layered nature of the reservoir, it is the view of ESG that there are significant additional recoverable oil reserves remaining in the field--hence the potential for additional in-fill wells.
 
A total of nine production wells were drilled into this reservoir up to 1995, all within a small crestal area. The early wells produced at initial rates of between 12,000 and 22,000 barrels of oil per day (which we refer to as “bopd”) and achieved cumulative production of up to 22 million barrels per well. The recent wells, however, have initial production rates at 1,500 - 2,000 bopd with cumulative production in excess of 1 million barrels, with water cuts in the order of 50% early in the life of the well. There is no pressure maintenance of the reservoir and gas lift is used to enhance oil production.
 
Extensive production facilities were installed during the life of the field and production from the wells was processed and exported through these facilities during the time of production and an operating fee of $3 per barrel was paid to Buttes.
 
Mubarek H2 Well

The operator of the drilling program, Crescent, secured a drilling rig and began drilling the first well, Mubarek H2, on January 31, 2006, which was completed during the second quarter of 2006 at a total depth of 15,020 feet (drilled depth). Initial logging of the well indicated good oil saturations over more than 100 feet in the Ilam/Mishrif reservoir section and the well was cased to enable testing of these zones. Crescent reported that the well was perforated over 6 zones totaling 129 feet, as two separate tests. The lowest zone was perforated over a 27- foot interval, which proved to be water bearing and was sealed off. The second test comprised perforations over 5 zones totaling 102 feet.

Based on initial testing, the well flowed in an unstable manner with a high water cut making accurate measurements difficult due to surging of the well. During periods when the well was flowing in a stable fashion, rates of 168 bopd and 2,259 bopd were recorded, based on limited testing over a period of approximately one month. On July 26, 2006, we announced that production at the H2 well had stabilized at 200 bopd. On October 11, 2006 we announced that production had increased to 461 bopd, accomplished by shutting off one zone that was contributing significant water and no oil.

The Mubarek H2 well was completed in the second quarter of 2006 and produced a total of 150,413 gross barrels through December 2009 when production was terminated.  In 2009, the well produced 4,811 barrels of oil, averaging 13 bopd.
 
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Mubarek K2-ST4 Well

The Mubarek K2-ST4 was drilled on the northwest part of the field proximal to the K1 location. Mubarek K1 was drilled as Thamama producer (a deeper gas condensate reservoir underlying the Ilam/Mishrif) and electric log readings over the Ilam/Mishrif section indicate good oil saturated reservoir. Drilling of the second well commenced during the second quarter of 2007.

On October 4, 2007, Crescent reported that the well was drilled to a total depth of 13,533 feet, some 100 feet into the Ilam oil reservoir, and had subsequently been stimulated with acid and put on production with gas lift from the Ilam reservoir. After initial tests, the well was flowing at 742 bopd.
 
Mubarek K2-ST4 well produced a total of 149,471 gross barrels through December 2009 when production was terminated. Mubarek K2-ST4 well produced 73,766 barrels of oil, averaging 202 bopd in 2009.
 
Other Projects:

Komi Republic - Russian Federation
 
In 2007, we acquired a minority stake in the development of an oilfield in the Komi Republic of the Russian Federation by acquiring a 3.9% interest, subject to dilution, in Pechora Energy through its UK parent company, Concorde Oil & Gas Plc. (which we refer to as “Concorde”). This acquisition was essentially a carried interest. Pechora Energy holds the production license for the Luzskoye field in the Komi Republic. During March 2010, Concorde’s directors noted that Concorde was in the process of disposing its operating assets to one of its majority shareholders - Kuwait Energy Company (which we refer to as “KEC”). The completion of this transaction is subject to a number of conditions, including regulatory consents, bank consent, and approval of KEC shareholders. As of December 31, 2010, the Company has not received any proceeds related to the disposition of these assets.
 
Employees and Consultants
 
As of December 31, 2010, we have retained the services of the following consultants and employees:
 
Karim Jobanputra serves as our Chief Executive Officer under a consulting agreement;
 
Michael Noonan serves as our interim Chief Financial Officer, Vice President - Corporate, and Secretary, under a consulting agreement; and
 
Shafiq Ur Rahman serves as our Manager of Finance and Administration under an employment agreement.
 
The Company does not currently carry key-man life insurance on key management. We also have a consulting agreement with ESG to provide technical services. Ian Baron, a former director of our Company, is a founding partner of ESG.
 
On February 5, 2007, we entered into a letter agreement with virtualcfo, Inc. (d/b/a/ vcfo), engaging the services of vcfo to provide oversight and guidance to our finance and accounting team. Under the agreement vcfo will assign staff members to assist us and will provide CFO level support, including assisting with operational and public reporting requirements, oversight and guidance of finance and accounting matters, and such other assistance as needed by our finance and accounting team.

On May 18, 2010, Sky Petroleum entered into a Consultant Agreement for Business Development in the Republic of Albania (“Consultant Agreement”) with Orsett Ventures Inc., a British Virgin Islands company (the “Consultant”).  The Consultant Agreement was amended on June 29, 2010, and October 8, 2010. Under the terms of the Consultant Agreement, Sky Petroleum retained the Consultant as an independent consultant to use the Consultant’s experience, know-how, qualifications and expertise to acquire and negotiate the acquisition of oil and gas properties and projects in the Republic of Albania.  The term is from May 18, 2010 through April 30, 2011, unless extended by mutual agreement of the Company and the Consultant or unless earlier terminated.

Subsequent to December 31, 2010, we entered into a consulting agreement effective February 1, 2011, with DT Premier Partners SH.P.K, an Albanian consulting company, to assist us with establishing our office and operations in Albania for a consulting fee of $3,500 per month.  The agreement is for a term of six months and renews on a month-to-month basis.

We have no other employees or consultants. In order to control costs and limit the number of our administrative personnel, we anticipate that we will retain consultants to provide or that our consultants will provide administrative type services until we are able to generate sufficient revenues from operations, if any, to hire personnel.
 

7
 

 

Competition

The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources. Many of these companies not only explore for and produce oil and natural gas, but also carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive oil and natural gas properties and exploratory prospects or define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may have a greater ability to continue exploration activities during periods of low oil and natural gas market prices. Our larger or integrated competitors may be able to absorb the burden of existing, and any changes to, federal, state, local and tribal laws and regulations more easily than we can, which would adversely affect our competitive position. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, because we have fewer financial and human resources than many companies in our industry, we may be at a disadvantage in bidding for exploratory prospects and producing oil and natural gas properties.

In Albania, our primary competitors are Bankers Petroleum Ltd., Petromanas Energy, Stream Oil and Gas Ltd., IEC Europetro plc, Cairn Energy plc, San Leon Energy plc, Beach Energy, Manas Petroleum Corp and Albpetro (the national Albanian oil company).
 
Government regulation
 
The operations of Buttes on the Ilam-Mishrif reservoir project in Sharjah, UAE are subject to governmental regulation applied through the Sharjah Supreme Petroleum Council (which we refer to as the “SPC”). The SPC controls well permitting and ensures operations are carried out in compliance with all applicable environmental and other regulation. Royalty payments and taxation as well as monitoring of oil lifts also come under the jurisdiction of the SPC.
 
Petroleum operations in the Republic of Albania and the PSC are generally governed by the Laws of the Republic of Albania, including the following laws and regulations:

 
Law No. 7746 dated 28.07.1993 “Petroleum Law (Exploration and Production)”, as amended (the “Petroleum Law”).
     
 
Law No. 7811 dated 12.04.1994 “On the Approval with Amendments of the Decree No. 782 dated 22.2.1994 “On the Fiscal System in the Petroleum Sector (Exploration-Production)”, as amended.
     
 
Law No. 9975, dated 28.07.2008, “On the National Taxes”, as amended.
     
 
Law No. 9946, dated 30.06.2008 “On the Sector of Natural Gas”, as amended.
     
 
Law No. 7928 “On Value Added Tax”, dated, 27.04.1995, as amended (the “VAT Law”).
     
 
Law No. 8976 dated 12.12.2002 “On Excises”, as amended (the “Excise Tax Law”).
     
 
Decision of Council of Ministers No. 547 dated 9.08.2006 “On Setting up the National Agency of Natural Resources”

These laws govern, among other petroleum related activities, the exploration and production of petroleum reserves in Albania, production taxes on petroleum production, and general business taxes for businesses operating in Albania.  Any changes to these laws and the regulations promulgated there under or the adoption of new laws and regulations in Albania could adversely affect our operations in Albania, decrease the potential profitability of those operations, or make such operations impossible or impracticable to continue.  The PSC is governed by Albanian regulations and law.

Reserves Reported to Other Agencies

No reserve estimates were filed with a Federal authority or agency other than with the SEC on Form 10-K.

Recent SEC Rule-Making Amendments

The SEC adopted amendments designed to modernize the SEC oil and gas company reserves reporting requirements, effective for years ending on or after December 15, 2009. Earlier adoption was not permitted. The most significant amendments to the requirements included the following:
 
Commodity Prices—Economic ability to produce reserves and discounted cash flows are now based on a 12-month average commodity price unless contractual arrangements designate the price to be used.
 
8
 
 

 
 
Disclosure of Unproved Reserves—Probable and possible reserves may be disclosed separately on a voluntary basis.
 
Proved Undeveloped Reserve Guidelines—Reserves may be classified as proved undeveloped if there is a high degree of confidence that the quantities will be recovered and the well from which the reserves are to be recovered is scheduled to be drilled within the next five years, unless the specific circumstances justify a longer time.
   
Reserves Estimation Using New Technologies—Reserves may be estimated through the use of reliable technology in addition to flow tests and production history.
 
Reserves Personnel and Estimation Process—Additional disclosure is required regarding the qualifications of the chief technical person who oversees the reserves estimation process. We are also required to provide a general discussion of our internal controls used to assure the objectivity of the reserves estimate.
 
Non-Traditional Resources—The definition of oil and gas producing activities has expanded and focuses on the marketable product rather than the method of extraction.
 
Production and Price Information
 
The following table summarizes sales volumes, sales prices, and production cost information for the periods indicated. The Company’s oil production comes from the Mubarek H2 and the Mubarek K2-ST4 wells located in the Mubarek Field in the UAE. We have no production in the United States. The Albania wells are currently under development, and as such, there was no production related to this project.
 
UAE, Mubarek Field
   
Year Ended
December 31, 2010
   
Year Ended
December 31, 2009
   
Year Ended
December 31, 2008
Sales
                 
Oil (bbls)
   
1,521
   
33,053
   
19,899
Oil and natural gas sales
                 
Oil sales
 
$
85,570
 
$
1,604,531
 
$
2,248,523
Average sales price
                 
Oil ($ per bbl)
 
$
56.26
 
$
48.54
 
$
113.00
Average production cost
                 
Total ($ per bbl)
 
$
3.00
 
$
3.00
 
$
3.00
 
Productive Wells and Acreage
 
As of December 31, 2010, we had no productive wells and acreage.

Undeveloped Acreage

Other than as noted in the Albania projects, the Company does not have any undeveloped acreage.

Drilling Activities

The Company had no drilling activities during the year ended December 31, 2010.

Present Activities and Delivery Commitments

As of the date of this Annual Report, the Company does not have any wells in the process of drilling, water floods being installed, pressure maintenance operations, or other similar oil and gas related activities which it is conducting.

As of the date of this Annual Report, the Company does not have any delivery commitments for oil and gas quantities in the future.

ITEM 1A. RISK FACTORS

There are many factors that affect our business, prospects, liquidity and the results of operations, some of which are beyond the control of the Company. The following is a discussion of some, but not all, of these and other important risk factors that may cause the actual results of our operations in future periods to differ materially from those currently expected or desired. Additional risks not presently known to management or risks that are currently believed to be immaterial, but which may become material, may also affect
 
 
9
 

 
 
our business, prospects, liquidity and results of operations. Our failure to successfully address the risks and uncertainties described below would have a material adverse effect on our business, financial condition and/or results of operations, and the trading price of our common stock may decline and investors may lose all or part of their investment. We cannot assure you that we will successfully address these risks or other unknown risks that may affect our business. Readers should carefully consider the risks and uncertainties described below before deciding whether to invest in shares of our common stock.

Risks related to our company and the oil and natural gas industry

Our petroleum operations in the Republic of Albania are regulated by the Laws of the Republic of Albania, which include petroleum production taxes and business taxes, and changes in these laws could adversely affect our operations in the Republic of Albania and decrease the potential profitability of those operations.

Petroleum operations in the Republic of Albania and the PSC are generally governed by the Laws of the Republic of Albania, including the following laws and regulations:

 
Law No. 7746 dated 28.07.1993 “Petroleum Law (Exploration and Production)”, as amended (the “Petroleum Law”).
     
 
Law No. 7811 dated 12.04.1994 “On the Approval with Amendments of the Decree No. 782 dated 22.2.1994 “On the Fiscal System in the Petroleum Sector (Exploration-Production)”, as amended.
     
 
Law No. 9975, dated 28.07.2008, “On the National Taxes”, as amended.
     
 
Law No. 9946, dated 30.06.2008 “On the Sector of Natural Gas”, as amended.
     
 
Law No. 7928 “On Value Added Tax”, dated, 27.04.1995, as amended (the “VAT Law”).
     
 
Law No. 8976 dated 12.12.2002 “On Excises”, as amended (the “Excise Tax Law”).
     
 
Decision of Council of Ministers No. 547 dated 9.08.2006 “On Setting up the National Agency of Natural Resources”

These laws govern, among other petroleum related activities, the exploration and production of petroleum reserves in Albania, production taxes on petroleum production, and general business taxes for businesses operating in Albania.  Any changes to these laws and the regulations promulgated there under or the adoption of new laws and regulations in Albania could adversely affect our operations in Albania, decrease the potential profitability of those operations, or make such operations impossible or impracticable to continue.  The PSC is governed by Albanian regulations and law.

Our operations in the Republic of Albania are subject to certain foreign operations risks regarding the economic and political stability of the Republic of Albania which could adversely affect our operations in the Republic of Albania and decrease the potential profitability of those operations.

The Company’s primary current activities and current assets are conducted and located in Albania. Albania commenced the transition from a communist regime to a modern open-market economy in 1992, with an extensive program of privatization in progress. While that transition has brought greater economic stability to the country, significant challenges still exist. Albania is not yet a member of the European Union and the country is heavily dependent on foreign investment due to its large trade deficit. Albania’s energy and transportation infrastructure is in need of significant investment, to add to the Albanian government’s recent embarkation on a major program of road and rail rehabilitation and construction. While the government of Albania encourages direct financial investment to aid the country’s economic development, it provides little by way of tax, financial or other incentives.
 
Albania, like other developing countries, from time-to-time may face political and social unrest, which may cause delays and uncertainties related to our business and operations in Albania.

There is no assurance that future political, social and economic conditions in Albania will not result in the government adopting different policies in relation to foreign development and ownership of petroleum resources. Any such changes in policy may result in changes to laws affecting the ownership of assets, cancellation or modification of contractual rights, foreign exchange restrictions, taxation, rates of exchange, environmental protection, labor relations, repatriation of income, return of capital, nationalization, expropriation, and other areas, any of which could adversely affect both the Company’s ability to undertake exploration and development activities in respect of properties in the manner currently contemplated, and its ability to continue to explore and profitably develop those properties in respect of which it has obtained exploration and development rights to date.
 
 
10
 

 
 
We may experience delays in production, marketing and transportation, if and when our projects in Albania result in oil production.

Various production, marketing and transportation conditions may cause delays in oil production and adversely affect the Company’s business. Drilling wells in areas remote from distribution and production facilities may delay production from those wells until sufficient reserves are established to justify construction of the necessary transportation and production facilities. The Company’s inability to complete wells in a timely manner would result in production delays. Because there is less developed infrastructure in some areas in Albania in which the Company holds its interests, the Company is subject to the risk that building of the necessary infrastructure will not be timely. In addition, marketing demands, which tend to be seasonal, may reduce or delay production from wells. The marketability and price of oil that may be acquired or discovered by the Company will be affected by numerous factors beyond the control of the Company. The Company is also subject to deliverability uncertainties related to the proximity of its reserves to adequate pipeline and processing facilities and extensive government regulation relating to price, taxes, royalties, licenses, land tenure, allowable production, and the export of oil and many other aspects of the petroleum business.

We may rely on third party providers in relation to certain of the activities we undertake on our Albania projects which will expose us to uncertain control issues and potential liabilities.

The Company or an affiliated entity designated by the Company will serve as operator under the PSC.  The Company intends to use affiliated entities to hold and operate the Concession Area under the PSC.  The Company may hire third parties to conduct certain activities in the Concession Area related to its commitments under the PSC.  The Company’s success will depend on its ability to provide adequate oversight of these third party providers and to ensure that the work provided is adequate for its purposes.  If the Company is unable to provide adequate oversight of the work being conducted, the Company’s operations in Albania could be adversely affected and the Company could be exposed to certain liabilities for the actions of the third party providers.

Our legal rights under the Participation Agreement are difficult to assess.

The assessment of economic viability of the Mubarek Field and the options available to the Company will be difficult to assess. We may not be able to enforce our rights under the Participation Agreement, and we may receive an unfavorable interpretation of the Concession Agreement and the Participation Agreement.

Because of our historical losses and expected losses in the future, it will be difficult to forecast when we will achieve profitability, if ever.

We have incurred net losses since our inception and expect to incur further losses for the foreseeable future.  It is difficult to determine when we will achieve profitability, if ever.  If we are unable to generate revenues and achieve profitability, we may be forced to go out of business.

We depend on our executive officers for critical management decisions and industry contacts.

We are dependent upon the continued services of Karim Jobanputra, our chief executive officer and Michael Noonan, our interim chief financial officer, vice president, corporate and secretary, who have significant experience in the oil and gas industry. We do not carry key person insurance on their lives. Mr. Jobanputra and Mr. Noonan are entrepreneurs and may not dedicate 100% of their business efforts to the business of Sky. Our executive officers and directors have other business interests, some of which may be in the oil and gas industry, and may serve on the board of directors or provide consulting services for other companies. The loss of the services of either of our executive officers, through incapacity or otherwise, would be costly to us and would require us to seek and retain other qualified personnel. See “Directors, Executive Officers, and Corporate Governance” below.

A substantial or extended decline in oil and natural gas prices could reduce our future revenue and earnings.

The price we receive for future oil and natural gas production will heavily influence our revenue, profitability, access to capital and rate of growth. Oil and natural gas are commodities and their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been volatile and in the recent past oil and natural gas prices have been significantly above historic levels. These markets will likely continue to be volatile in the future and current prices for oil and natural gas may decline in the future. The prices we may receive for any future production, and the levels of this production, depend on numerous factors beyond our control. These factors include the following:

changes in global supply and demand for oil and natural gas
 
actions by the Organization of Petroleum Exporting Countries, or OPEC;
 
actions by non OPEC countries;
 
11
 

 

 
political conditions, including embargoes, which affect other oil-producing activities;
 
levels of global oil and natural gas exploration and production activity;
 
levels of global oil and natural gas inventories;
 
weather conditions affecting energy consumption;
 
technological advances affecting energy consumption; and
 
prices and availability of alternative fuels.
 
Lower oil and natural gas prices may not only decrease our future revenues but also may reduce the amount of oil and natural gas that we can produce economically. A substantial or extended decline in oil or natural gas prices may reduce our earnings, cash flow and working capital and may subject us to full cost ceiling impairment.

Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could substantially increase our costs and reduce our profitability.

Oil and natural gas exploration is subject to numerous risks beyond our control; including the risk that drilling will not result in any commercially viable oil or natural gas reserves.

The total cost of drilling, completing and operating wells will be uncertain before drilling commences. Overruns in budgeted expenditures are common risks that can make a particular project uneconomic. Further, many factors may curtail, delay or cancel drilling, including the following:

delays imposed by or resulting from compliance with regulatory requirements;
 
pressure or irregularities in geological formations;
 
shortages of or delays in obtaining equipment and qualified personnel;
 
equipment failures or accidents;
 
adverse weather conditions;

reductions in oil and natural gas prices; and

limitations in the market for oil and natural gas.

We may incur substantial losses and be subject to substantial liability claims as a result of our oil and natural gas operations.

Our operations will be subject to risks associated with oil and natural gas operations. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect the payment of production revenues to us, if any. Our oil and natural gas exploration activities will be subject to all of the operating risks associated with drilling for and producing oil and natural gas, including the possibility of:

environmental hazards, such as uncontrollable flows of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater contamination;

abnormally pressured formations;

mechanical difficulties, such as stuck oilfield drilling and service tools and casing collapse;

Unexpected failures of key equipment used in the oil and gas production process;

fires and explosions;

personal injuries and death; and
 
12
 

 


 
natural disasters.

Any of these risks could adversely affect our ability to operate or result in substantial losses. These risks may not be insurable or we may elect not to obtain insurance if the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event that is not fully covered by insurance occurs, it could adversely affect us.

Market conditions or operational impediments may hinder our access to oil and natural gas markets or delay our production.

Market conditions or the unavailability of satisfactory oil and natural gas transportation arrangements may hinder access to oil and natural gas markets or delay production, if any, on our properties. The availability of a ready market for our future oil and natural gas production will depend on a number of factors, including the demand for and supply of oil and natural gas and the proximity of reserves to pipelines and terminal facilities.

We are subject to complex laws that can affect the cost, manner and feasibility of doing business thereby increasing our costs and reducing our profitability.

Development, production and sale of oil and natural gas are subject to laws and regulations. Matters subject to regulation include:

permits for drilling operations;

reports concerning operations;

spacing of wells;

unitization and pooling of properties; and

taxation.

Failure to comply with these laws may also result in the suspension or termination of operations and liabilities under administrative, civil and criminal penalties. Moreover, these laws could change in ways that substantially increase the costs of doing business. Any such liabilities, penalties, suspensions, terminations or regulatory changes could materially and adversely affect our financial condition and results of operations.

The unavailability or high cost of drilling rigs, equipment, supplies, personnel and oilfield services could adversely affect our ability to execute our plans on a timely basis and within our budget.

Shortages or the high cost of drilling rigs, equipment, supplies or personnel could delay or adversely affect development operations on our properties, which could have a material adverse effect on our business, financial condition or results of operations. Rising or unforeseen costs related to drilling and technical engineering may increase the cost related to drilling and completing the wells, which may either require us to contribute additional capital to drilling of the wells or cause dilution in our right to receive revenue from production, if any.

Competition in the oil and natural gas industry is intense, which may increase our costs and otherwise adversely affect our ability to compete.

We operate in a highly competitive environment for prospects suitable for exploration, marketing of oil and natural gas and securing the services of trained personnel. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours, which can be particularly important in the areas in which we operate. Those companies may be able to pay more for prospective oil and natural gas properties and prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. In order for us to compete with these companies, we may have to increase the amounts we pay for prospects, thereby reducing our profitability.

We may not be able to compete successfully in acquiring prospective reserves, developing reserves, marketing oil and natural gas, attracting and retaining quality personnel and raising additional capital.

Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, there is substantial competition for capital available for investment in the oil and natural gas industry. Our inability to compete successfully in these areas could have a material adverse effect on our business, financial condition or results of operations.
 
 
13
 

 
 
Recent market events and general economic conditions.

The recent unprecedented events in global financial markets have had a profound impact on the global economy. Many industries, including the oil and gas industry, are impacted by these market conditions. Notwithstanding various actions by the U.S. and foreign governments, concerns about the general condition of the capital markets, financial instruments, banks, investment banks, insurers and other financial institutions could cause the broader credit markets to further deteriorate and stock markets to decline substantially. In addition, general economic indicators have deteriorated, including declining consumer sentiment, increased unemployment and declining economic growth and uncertainty about corporate earnings.

These unprecedented disruptions in the current credit and financial markets have had a significant material adverse impact on a number of financial institutions and have limited access to capital and credit for many companies. These disruptions could, among other things, make it more difficult for us to obtain, or increase its cost of obtaining, capital and financing for its operations. A continued or worsened slowdown in the financial markets or other economic conditions, including but not limited to, consumer spending, employment rates, business conditions, inflation, fuel and energy costs, consumer debt levels, lack of available credit, the state of the financial markets, interest rates, and tax rates may adversely affect our growth and profitability. Specifically:

the global credit/liquidity crisis could impact the cost and availability of financing and our overall liquidity;

the volatility of oil and gas prices may impact our revenues, profits and cash flow;

volatile energy prices, commodity and consumables prices and currency exchange rates impact potential production costs; and

the devaluation and volatility of global stock markets impacts the valuation of our equity securities

These factors could have a material adverse effect on our financial condition and results of operations.

Increased costs and compliance risks as a result of being a public company.

Legal, accounting and other expenses associated with public company reporting requirements have increased significantly in the past few years. We anticipate that general and administrative costs associated with regulatory compliance will continue to increase with ongoing compliance requirements under the Sarbanes-Oxley Act of 2002, as well as any new rules implemented by the SEC in the future. These rules and regulations have significantly increased our legal and financial compliance costs and made some activities more time-consuming and costly. There can be no assurance that the Company will continue to effectively meet all of the requirements of these regulations, including Sarbanes-Oxley Section 404. Any failure to effectively implement internal controls, or to resolve difficulties encountered in their implementation, could harm our operating results, cause us to fail to meet reporting obligations or result in management being required to give a qualified assessment of our internal controls over financial reporting or our independent auditors providing an adverse opinion regarding management’s assessment, if and when such assessment is required. Any such result could cause investors to lose confidence in our reported financial information, which could have a material adverse effect on the trading price of our common shares. These rules and regulations have made it more difficult and more expensive for us to obtain director and officer liability insurance, and we may be required to accept reduced policy limits and coverage or incur substantially higher costs to obtain the same or similar coverage in the future. As a result, it may be more difficult for us to attract and retain qualified individuals to serve on our board of directors or as executive officers. If we fail to maintain the adequacy of our internal control over financial reporting, our ability to provide accurate financial statements and comply with the requirements of the Sarbanes-Oxley Act of 2002 could be impaired, which could cause our stock price to decrease.

We have never declared or paid cash dividends on our common stock. We currently intend to retain future earnings to finance the operation, development and expansion of our business.

We do not anticipate paying cash dividends on our common stock in the foreseeable future. Payment of future cash dividends, if any, will be at the discretion of our board of directors and will depend on our financial condition, results of operations, contractual restrictions, capital requirements, business prospects and other factors that our board of directors considers relevant.

Accordingly, investors will only see a return on their investment if the value of our securities appreciates.

The market for our common shares has been volatile in the past, and may be subject to fluctuations in the future.

The market price of our common stock on the OTCBB has ranged from a high of $0.96 and a low of $0.06 during the twelve-month period ended December 31, 2010. As of March 23, 2011, the market price for our common stock closed at $0.46 on the OTCBB. See “Market for Registrant’s Common Equity, and Related Stockholder Matters and Issuer Purchases of Equity Securities”. We cannot assure you that the market price of our common stock will not significantly fluctuate from its current level. The market price of our common stock may be subject to wide fluctuations in response to quarterly variations in operating results, changes in financial
 
 
14

 

estimates by securities analysts, or other events or factors. In addition, the financial markets have experienced significant price and volume fluctuations for a number of reasons, including the failure of the operating results of certain companies to meet market expectations that have particularly affected the market prices of equity securities of many companies that have often been unrelated to the operating performance of such companies. These broad market fluctuations, or any industry-specific market fluctuations, may adversely affect the market price of our common stock. In the past, following periods of volatility in the market price of a company’s securities, class action securities litigation has been instituted against such a company. Such litigation, whether with or without merit, could result in substantial costs and a diversion of management’s attention and resources, which would have a material adverse affect on our business, operating results and financial condition.

Broker-dealers may be discouraged from effecting transactions in our common stock because our common shares are considered a penny stock and are subject to the penny stock rules.

Rules 15g-1 through 15g-9 promulgated under the Securities Exchange Act of 1934 (“Exchange Act”), as amended impose sales practice and disclosure requirements on certain brokers-dealers who engage in certain transactions involving a penny stock.” Subject to certain exceptions, a penny stock generally includes any non-NASDAQ equity security that has a market price of less than $5.00 per share. The market price of our common stock on the OTCBB during the period from November 6, 2003 to December 31, 2010, ranged between a high of $3.20 and a low of $0.03 per share, and our common stock is deemed penny stock for the purposes of the Exchange Act. The additional sales practice and disclosure requirements imposed upon brokers-dealers may discourage broker-dealers from effecting transactions in our common stock, which could severely limit the market liquidity of the stock and impede the sale of our stock in the secondary market.

A broker-dealer selling penny stock to anyone other than an established customer or accredited investor,” generally, an individual with net worth in excess of $1,000,000 or an annual income exceeding $200,000, or $300,000 together with his or her spouse, must make a special suitability determination for the purchaser and must receive the purchaser’s written consent to the transaction prior to sale, unless the broker-dealer or the transaction is otherwise exempt. In addition, the penny stock regulations require the broker-dealer to deliver, prior to any transaction involving a penny stock, a disclosure schedule prepared by the SEC relating to the penny stock market, unless the broker-dealer or the transaction is otherwise exempt. A broker-dealer is also required to disclose commissions payable to the broker-dealer and the registered representative and current quotations for the securities. Finally, a broker-dealer is required to send monthly statements disclosing recent price information with respect to the penny stock held in a customer’s account and information with respect to the limited market in penny stocks.

ITEM 1B. UNRESOLVED STAFF COMMENTS

Not Applicable

ITEM 2. PROPERTIES

Our principal corporate and executive offices are located at 401 Congress Avenue, Suite 1540, Austin, Texas 78701. Our telephone number is (512) 687-3427. We rent our corporate office space on a month-to-month basis at $2.500 per month. We do not currently maintain any investments in real estate, real estate mortgages or securities of persons primarily engaged in real estate activities, nor do we expect to do so in the foreseeable future.

We entered into a Participation Agreement for the financing of a drilling program in the Mubarek field, an offshore region in a concession area surrounding Abu Musa Island in the Arabian Gulf. Under the terms of the Participation Agreement, Sastaro has the right to participate in a share of the future production revenue by contributing $25 million in drilling costs related to two wells, H2 and K2-ST4 in an off-shore oil and gas project in the UAE. The Participation Agreement does not grant Sastaro any interest in the Mubarek Concession Area. Sastaro’s rights are limited to receiving a share of future production revenue, if any.

Sky Petroleum has exclusive rights to three exploration blocks (Block Four, Block Five and Block Dumre) in the Republic of Albania (the “Concession Area”). The Concession Area covers approximately 1.2 million acres, representing approximately 20% of the landmass of Albania. The PSC has a seven-year term with three exploration periods. Upon commercial discovery of gas, the agreement allows for development and production periods of 25 years plus extensions at the Company’s option.

ITEM 3. LEGAL PROCEEDINGS

We are not aware of any material pending or threatened litigation or of any proceedings known to be contemplated by governmental authorities which are, or would be, likely to have a material adverse effect upon us or our operations, taken as a whole. There are no material proceedings pursuant to which any of our directors, officers or affiliates or any owner of record or beneficial owner of more than 5% of our securities or any associate of any such director, officer or security holder is a party adverse to us or has a material interest adverse to us.
 
 
15
 

 

ITEM 4. [REMOVED AND RESERVED]

PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Market Information

Our common stock is quoted as “SKPI” on the Over the Counter Bulletin Board (which we refer to as the “OTCBB”), which is sponsored by the Financial Industry Regulatory Authority (which we refer to as “FINRA”). The OTCBB is a network of security dealers who buy and sell stock. The dealers are connected by a computer network, which provides information on current “bids” and “asks” as well as volume information. The OTCBB is not considered a “national exchange.” Our common stock commenced trading on the OTCBB on November 3, 2003.

The high and low bid quotations of our common stock on the OTC Bulletin Board as reported by the FINRA were as follows:

Period
 
High
 
Low
 
2010
         
First Quarter
 
$
0.25
 
$
0.10
 
Second Quarter
 
$
0.34
 
$
0.06
 
Third Quarter
 
$
0.96
 
$
0.16
 
Fourth Quarter
 
$
0.90
 
$
0.33
 
2009
         
First Quarter
 
$
0.11
 
$
0.04
 
Second Quarter
 
$
0.26
 
$
0.06
 
Third Quarter
 
$
0.49
 
$
0.08
 
Fourth Quarter
 
$
0.43
 
$
0.21
 

The above quotations reflect inter-dealer prices, without retail mark-up, markdown or commission and may not necessarily represent actual transactions.

As of December 31, 2010, the closing bid quotation for our common stock was $0.44 per share as quoted by the OTCBB. On March 23, 2011, the closing bid quotation on our common stock was $0.46.

Holders

As of March 25, 2011, we had 61,868,709 shares of common stock issued and outstanding, held by 30 registered stockholders.
 
Dividends

The declaration of dividends on our common shares is within the discretion of our board of directors and will depend upon the assessment of, among other factors, results of operations, capital requirements and the operating and financial condition of the Company. The Board has never declared a dividend on the common shares. At the present time, we anticipate that all available funds will be invested to finance the growth of our business.
 


16
 

 
 
Securities Authorized for Issuance under Equity Compensation Plans

EQUITY COMPENSATION PLAN INFORMATION

     
Number of securities to be issued upon exercise of outstanding options, warrants, and rights
   
Weighted-average exercise price of outstanding options, warrants, and rights
   
Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
 
     
(a)
   
(b)
   
(c)
 
Equity compensation plans approved by security holders(1)
   
2,450,000
 
$
0.85
   
7,508,471
 

 
(1)
We have two stock option plans: a stock incentive plan for non-U.S. residents and a stock incentive plan for U.S. residents. Our stock incentive plan for non-U.S. residents authorizes the issuance of stock options to acquire up to 10% (currently 6,186,871 shares) of our issued and outstanding shares of common stock, and our stock incentive plan for U.S. residents authorizes the issuance of stock options to acquire up to a maximum of 3,321,600 shares of common stock (less the number of shares issuable upon exercise of options granted by us under all other stock incentive plans on the date of any grant under the U.S. plan). As of December 31, 2010, 1,350,000 options were granted under the U.S. plan and 1,100,000 options were granted under the non-U.S. plan. A total of 5,536,871 options are available for grant under the Non-U.S. Plan and a total of 1,971,600 are available for grant under the U.S. Plan.

We adopted an incentive stock plan for non-U.S. residents on July 26, 2005, and an incentive stock plan for U.S. residents on August 25, 2005. Our stock incentive plan for non-U.S. residents authorizes the issuance of stock options to acquire up to 10% of our issued and outstanding shares of common stock and our stock incentive plan for U.S. residents authorizes the issuance of stock options to acquire up to a maximum of 3,321,600 shares of common stock (less the number of shares issuable upon exercise of options granted by us under all other stock incentive plans on the date of any grant under the plan).

Adoption of Non-U.S. Stock Option Plan

On July 26, 2005, we adopted, and on July 31, 2006, our stockholders approved, the Sky Petroleum, Inc. Non-U.S. Stock Option Plan, effective as of April 1, 2005. The Non-U.S. Plan authorizes the issuance of stock options to acquire up to 10% of our issued and outstanding shares of common stock. The purpose of the Non-U.S. Plan is to aid us in retaining and attracting Non-U.S. residents that are capable of enhancing our prospects for future success, to offer such personnel additional incentives to exert maximum efforts for the success of our business, and to afford such personnel an opportunity to acquire a proprietary interest in the company through stock options. Our Compensation Committee administers the Non-U.S. Plan and determines the terms and conditions under which options to purchase shares of our common stock may be awarded. The term of an option granted under the Non-U.S. Plan cannot exceed seven years and the exercise price for options granted under the Non-U.S. Plan cannot be less than the fair market value of our common stock on the date of grant.

Adoption of 2005 U.S. Stock Incentive Plan

On August 25, 2005, we adopted, and on July 31, 2006 our stockholders approved, the Sky Petroleum, Inc. 2005 U.S. Stock Incentive Plan for U.S. residents. The U.S. Plan authorizes the issuance of stock options and other awards to acquire up to a maximum of 3,321,600 shares of our common stock (less the number of shares issuable upon exercise of options granted by us under all other stock incentive plans on the date of any grant under the plan). The purpose of the U.S. Plan is to aid the Company in retaining and attracting U.S. personnel capable of enhancing our prospects for future success, to offer such personnel additional incentives to exert maximum efforts for the success of our business, and to afford such personnel an opportunity to acquire a proprietary interest in the company through stock options and other awards. The U.S. Plan provides for the grant of incentive stock options (within the meaning of Section 422 of the Internal Revenue Code of 1986, as amended), options that are not incentive stock options, stock appreciation rights and various other stock-based grants. Our Compensation Committee administers the U.S. Plan and determines the terms and conditions under which options to purchase shares of our common stock or other awards may be granted to eligible participants. The term of an incentive stock option granted under the U.S. Plan cannot exceed ten years and the exercise price for options granted under the U.S. Plan cannot be less than the fair market value of our common stock on the date of grant.

Sales of Unregistered Securities

During the year ended December 31, 2010, the Company sold and issued the following securities that were not registered under the Securities Act of 1933, as amended.
 
 
17
 

 
 
On June 24, 2010, we issued 25,000 shares of common stock to Oliver Whittle, a director, as a signing bonus for becoming a member of the board of directors of the Company.

On September 22, 2010, we issued 1,500,000 shares of common stock to Orsett Ventures Inc., for consulting services.

On October 6, 2010, we issued 50,000 shares of common stock to H. E. Sheikh Jabor Bin Jassim Al Thani, a director, as a signing bonus for becoming a member of the board of directors of the Company.

On December 3, 2010, we issued 1,500,000 shares of common stock to Orsett Ventures Inc., for consulting services.

On December 3, 2010, we issued 3,863,636 shares of Series B Preferred Stock to Orsett Ventures Inc., for consulting services.

All of the securities issued during the year ended December 31, 2010, were issued pursuant to exemptions from the registration requirements of the Securities Act of 1933, as amended, available under Rule 903 of Regulation S.  The securities were issued in off-shore transactions to non-U.S. persons and are “restricted securities” as defined Rule 144(a) (3) of the Securities Act of 1933, as amended.

Repurchase of Securities
 
During the period covered by this Annual Report, neither us nor any of our affiliates repurchased common shares of the Company registered under Section 12 of the Exchange Act of 1934, as amended.
 
ITEM 6. SELECTED FINANCIAL DATA
 
Not applicable.
 
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
 
You should read the following discussion and analysis of our financial condition and results of operations together with our consolidated financial statements and related notes appearing elsewhere in this Annual Report. This discussion and analysis contains forward-looking statements that involve risks, uncertainties and assumptions. Our actual results may differ materially from those anticipated in these forward-looking statements as a result of many factors, including, but not limited to, those set forth under “Risk Factors” above and elsewhere in this Annual Report. See section” Cautionary Note Regarding Forward-Looking Statements” above.
 
This discussion and analysis should be read in conjunction with the accompanying consolidated financial statements of the Company and related notes. The discussion and analysis of the financial condition and results of operations are based upon the consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires the Company to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of any contingent liabilities at the financial statement date and reported amounts of revenue and expenses during the reporting period. On an on-going basis the Company reviews its estimates and assumptions. The estimates were based on historical experience and other assumptions that the Company believes to be reasonable under the circumstances. Actual results are likely to differ from those estimates under different assumptions or conditions, but the Company does not believe such differences will materially affect our financial position or results of operations. Critical accounting policies, the policies the Company believes are most important to the presentation of its financial statements and require the most difficult, subjective and complex judgments, are outlined below in the sub-section Management’s Discussion and Analysis of Financial Condition and Results of Operations - Critical Accounting Policies,” and have not changed significantly.

Overview and Plan of Operations

Our primary business is to identify opportunities to either make direct property acquisitions or to fund exploration or development of oil and natural gas properties of others under arrangements in which we will finance the costs in exchange for interests in the oil or natural gas revenue generated by the properties. Such arrangements are commonly referred to as farm-ins to us, or farm-outs by the property owners farming out to us. There can be no assurance that we will successfully implement our business strategy or meet our goals during the next twelve months, if ever.
 
 
18

 
Production Sharing Contract with the Ministry of Economy, Trade and Energy of Albania:

On June 24, 2010, Sky entered into a Production Sharing Contract with the Ministry of Economy, Trade and Energy of Albania, acting through the National Agency of Natural Resources of Albania.  An official copy of the document evidencing approval by the Council of Ministers of the Republic of Albania of the PSC was published in the Fletoren Zyrtare on December 17, 2010, and the PSC became effective ten working days thereafter on January 3, 2011. The PSC grants Sky Petroleum exclusive rights to three exploration blocks (Block Four, Block Five and Block Dumre) in the Republic of Albania (the “Concession Area”). The Concession Area covers approximately 1.2 million acres, representing approximately 20% of the landmass of Albania. The PSC has a seven-year term with three exploration periods. Upon commercial discovery of gas, the agreement allows for development and production periods of 25 years plus extensions at the Company’s option. To date, there have been more than ten identified prospects including three significant evaluation wells in each block: Palokastra well Block Four, Kanina well in Block Five, and a Dumre well.

First Exploration Period: The first exploration period is an initial period of two years in which Sky Petroleum has agreed to undertake G&G, including but not limited to acquisition of technical data, interpretation of geological, geophysical and well data, and conducting regional geological and structural studies (mapping, balanced cross sections); seismic reprocessing and seismic acquisition, with minimum expenditure commitments totaling $1,500,000.

Second Exploration Period:  Provided that Sky Petroleum has completed the minimum first exploration period work program or paid AKBN the minimum expenditure amount, Sky Petroleum may elect to extend the exploration period into a second exploration period of three years.  During the second exploration period, Sky Petroleum will undertake G&G; seismic acquisition and an exploration drilling program with minimum expenditure commitments totaling $2,650,000.

At the end of the first or second exploration period, Sky Petroleum shall have the right, subject to AKBN approval, to extend such periods by one year, reducing the later periods by one year.

Third Exploration Period:  Provided that Sky Petroleum has completed the minimum second exploration period work program or paid AKBN the minimum expenditure amount, if, as approved by the AKBN, there are special circumstances which require more time for the contractor to perform adequate exploration activity, Sky Petroleum may elect to extend the exploration period into a third exploration period of two years.  During the third exploration period, Sky Petroleum will undertake G&G; seismic acquisition and an exploration drilling program with minimum expenditure commitments totaling $3,150,000.

If during the exploration periods, Sky Petroleum discovers petroleum accumulations capable of commercial production within the Concession Area (a “Discovery Area”); it can submit to AKBN a development plan and commence development of the Discovery Area.  Sky Petroleum will have production rights of 25 years for each field (a “Production Area”) from the date of initial commercial production, which may be extended, at Sky Petroleum’s option, for successive periods of five years on the same conditions, subject to approval by AKBN, which approval shall not be unreasonably withheld or delayed.  Sky Petroleum and AKBN will share profits from any commercial production of oil (after cost recovery by Sky Petroleum) based on a sliding scale formula, in which Sky Petroleum’s share of profits will range from 96% to 100%.  All available production is subject to a 10% royalty tax and Sky Petroleum’s profits are subject to a 50% Albania tax on petroleum profits.

Sky Petroleum will relinquish to AKBN 25% of the Concession Area, as designated by Sky Petroleum, within 180 days after the end of each of the First Exploration Period and the Second Exploration Period and all remaining acreage of the Concession Area at the end of the Third Exploration Period, that is not then subject to a Discovery or in a Production Area.  Sky Petroleum will not be required to relinquish areas included in a Discovery Area or in Production Area.

Sky Petroleum or an affiliated entity designated by Sky Petroleum will serve as operator under the Agreement. Sky Petroleum intends to use affiliated entities to hold and operate the Concession Area. Sky Petroleum organized a Cayman Island corporation for the purpose of holding and operating the Concession.

The Company’s investment in the Albania exploration blocks as of December 31, 2010 was $10,115,220.  This investment consisted of acquisition costs related to the PSC totaling $50,000, $850,000 for fees to consultants for locating and negotiating our investment in the Albania exploration blocks, and $225,220 for fees related to evaluations and assessments of the concession area.  In addition, 3,000,000 shares of common stock with a fair value of $1,170,000, plus 3,863,636 Preferred Shares Series B with a value of $7,820,000, were issued to the Consultant for expertise provided to the Company in acquiring and negotiating the acquisition of oil and gas properties in Albania.  See, “Consulting Agreement”, below.

Consulting Agreement:

On May 18, 2010, Sky Petroleum entered into a Consultant Agreement with Orsett Ventures Inc., a British Virgin Islands company (the “Consultant”).  The Consultant Agreement was amended on June 29, 2010 (Amendment #1) and on October 8, 2010 (Amended #2). Under the terms of the Agreement, Sky Petroleum retained Consultant as an independent consultant to use Consultant’s experience, know-how, qualifications and expertise to acquire and negotiate the acquisition of oil and gas properties and projects in
 
 
19
 

 
 
the Republic of Albania.  The term is from May 18, 2010 through April 30, 2011, unless extended by mutual agreement of the Parties or unless earlier terminated. The Consultant’s fees were due upon execution of first and second qualifying transactions.

First Qualifying Transaction

Pursuant to Amendment #1, Sky Petroleum agreed to pay the Consultant in connection with the execution and delivery of the PSC $700,000 and 1,500,000 shares of common stock, all of which was paid and tendered, respectively as of December 31, 2010.

Pursuant to Amendment #2, Sky agreed to pay the Consultant for additional services, $150,000, an additional 1,500,000 shares of common stock; and 3,863,636 shares of Preferred Series B stock.  On December 3, 2010, following notification of approval by the Council of Ministers for the Republic of Albania of the PSC, the Company issued the Preferred Series B Stock. As of December 31, 2010, all fees and common and preferred shares were paid and tendered.

The fair market value of the 3 million shares of common stock of $1,170,000, and the fair market value of the 3,863,636 shares issued of $7,820,000 has been included in oil and gas investments as of December 31, 2010.  

Total consultant costs of $9,840,000 is included in the Company’s investment in the Albania exploration blocks (oil and gas properties) totaling $10,115,220 as of December 31, 2010.  This investment consisted of acquisition costs related to the PSC totaling $50,000, and $850,000 for fees to consultants for locating and negotiating our investment in the Albania exploration blocks, and $225,220 for fees related to evaluations and assessments of the concession area.  In addition, 3,000,000 shares of common stock with a fair value of $1,170,000, plus 3,863,636 Preferred Shares Series B with a value of $7,820,000, are also included in our investment in Albania projects.

Mubarek Field - Participation Agreement:

On May 18, 2005, the Company entered into a Participation Agreement with Buttes, a wholly-owned subsidiary of Crescent for the financing of a drilling program. The project is located in the Ilam/Mishrif reservoir of the Mubarek Field area near Abu Musa Island in the Arabian Gulf. Under the terms of the Participation Agreement, the Company participated in a share of the future production revenue by contributing $25 million in drilling and completion costs related to two in-fill wells in an off-shore oil and gas project in the United Arab Emirates. The operator of the drilling program, Crescent, secured a drilling rig and began drilling the first well, Mubarek H2, which was completed during the second quarter of 2006 at a total depth of 15,020 feet (drilled depth). The second well Mubarek K2-ST4 was completed on October 4, 2007, with a total depth of 13,533 feet. Since the Mubarek H2 well was completed, it has produced a total of 150,413 gross barrels as of December 31, 2010. Since the Mubarek K2-ST4 well was completed, it has produced a total of 149,471 gross barrels as of December 31, 2010.

On December 31, 2009, the Company received written notice from Buttes that Buttes unilaterally and solely determined that the Mubarek Field had reached the end of its economic life. Buttes also notified Sastaro that the Concession Agreement, dated December 29, 1969, between the His Highness Sheikh Sultan bin Mohamed Al-Qassimi III, The Ruler of Sharjah, UAE and Buttes with respect to the Mubarek Field was terminated. Buttes have stated that it handed over the Mubarek Field operations and facilities to representatives of His Highness Sheikh Sultan bin Mohamed Al-Qassimi III on December 28, 2009. Management is exercising its rights under the Participation Agreement and intends to take all actions required to protect our interests, our shareholders and our investment in the Mubarek Field.

Komi Republic - Russian Federation:
 
In 2007, we acquired a minority stake in the development of an oilfield in the Komi Republic of the Russian Federation by acquiring a 3.9% interest, subject to dilution, in Pechora Energy through its UK parent company, Concorde Oil & Gas Plc. (which we refer to as “Concorde”). This acquisition was essentially a carried interest. Pechora Energy holds the production license for the Luzskoye field in the Komi Republic. During March 2010, Concorde’s directors noted Concorde was in the process of disposing its operating assets to one of its majority shareholders - Kuwait Energy Company (which we refer to as “KEC”). The completion of this transaction is subject to a number of conditions, including regulatory consents, bank consent, and approval of KEC shareholders. As of December 31, 2010, the Company has not received any proceeds related to the disposition of these assets.

Comparison of 2010 Statement of Operations to 2009 Statement of Operations (all amounts in approximation)

Net Losses:

During the year ended December 31, 2010, we had a net loss of $1,581,000 as compared to a net loss of $1,774,000 during the year ended December 31, 2009, for a total decrease in losses of $193,000 and 11%. Net loss decreased from 2009 to 2010 due primarily to a reduction of total expenses by $1,717,000, offset by a reduction on oil revenues of $1,519,000.
 

20
 

 

Losses from Mubarek field operations:

We had four lifts from the Mubarek wells during 2009 with revenues of $1,605,000, compared to $86,000 for one final lift from remaining inventory during the second quarter of our fiscal year ended December 31, 2010. The decline in total revenues is due to the abandonment of the well by the operator in late December 2009. A full cost ceiling impairment charge of $231,000 was recorded in 2009 reducing the investment to zero. As a result, there was also $0 depletion in 2010 compared to $831,000 in 2009, and lease operating costs of $34,000 in 2010 versus $120,000 in 2009. Revenues from the Mubarek wells declined in total in 2010 by $1,519,000 from 2009, along with overall decreases in related well operations of $1,149,000, for a net increase in losses to the Company of $370,000 for 2010. We do not anticipate any revenues from operations in 2011.

Operating expenses:

Total operating expenses in 2010 of $1,668,000 as compared to total operating expenses of $3,385,000 for 2009, decreased in total in 2010 by $1,717,000 or 52%.

Decreases in operating expenses in 2010 as compared to 2009 of $2,247,000 are primarily as a result of the following:

Decrease in costs in 2010 related to the Mubarek field operations as noted above totaling $1,149,000.
Impairment on an investment in a non-affiliated entity for $1,000,000 was reported in 2009 versus $0 for 2010.
Other general and administrative expenses decreased $98,000 overall in 2010.

The above decreases in operating expenses are offset by the following increases in expenses overall of $531,000 in 2010 as compared to 2009 and are primarily as a result of the following:

As a result of our new acquisitions in Albania, travel expenses increased by $224,000 in 2010.
An increase of $179,000 was incurred for legal and accounting expenses in pursuit of Albania projects, and in pursuit of enforcing the Participation Agreement for the Mubarek wells in 2010.
Stock-based compensation increased by $98,000 as a result of stocks and options issued to officers and directors in 2010.
Increases of $30,000 related to consulting expenses in 2010.

We expect operating expenses to increase in 2011 as we fund our expenditures obligations under the PSC. General and administrative expenses are expected to increase in 2011 as we fund expenditures and hire additional employees and consultants in connection with our exploration and development of activities in Albania. Expenses may also increase if we elect to pursue additional projects or properties.

Liquidity and Capital Resources

A component of our operating plan is the ability to obtain additional capital through additional equity and/or debt financing to fund our Albania projects. Our only source of internal operating cash flow historically has been derived from our participation interest in the Mubarek Field, which ceased production at the end of 2009. We had cash on hand of approximately $2,900,000 at December 31, 2010.

Since inception, we have financed our cash flow requirements through the issuance of common stock and preferred stock and our working interest in the Mubarek Field. As we expand our activities, we expect to continue to experience net negative cash flows from operations. Additionally we anticipate obtaining additional financing to fund operations and exploration and development activities through common stock or preferred stock offerings, debt financings and bank borrowings, to the extent available, or to obtain additional financing to the extent necessary to augment working capital.

Recently, the poor conditions in the U.S. housing market and the credit quality of mortgage backed securities have caused a loss of confidence in the broader U.S. and global credit and financial markets, resulting in the collapse of, and government intervention in, major banks, financial institutions and insurers and creating a climate of greater volatility, less liquidity, widening of credit spreads, a lack of price transparency, increased credit losses and tighter credit conditions. These disruptions continued into 2010. The current credit and financial markets have had a significant material adverse impact on a number of financial institutions and have limited access to capital and credit for many companies. These disruptions could, among other things, make it more difficult for us to obtain, or increase our cost of obtaining, capital and financing for our operations in the future. Our access to additional capital may not be available on terms acceptable to us or at all.
 
 
21
 

 
 
We expect to rely upon additional financing or arrangements with working interests to fund our future operations. If costs increase substantially or we incur greater losses than expected, our operations will be reliant upon equity financings to continue into the future. The current market conditions could make it difficult or impossible for us to raise necessary funds to meet our capital requirements. If we are unable to obtain financing through equity investments, we will seek multiple solutions including, but not limited to, credit facilities or debenture issuances.

Net cash used in operating activities during the year ended December 31, 2010 was approximately $978,000 as compared to net cash used in operating activities of approximately $214,000 for the comparable period in 2009, a reduction of $764,000. Cash used in investing activities in 2010 of $1,134,000 included $1,125,000 for purchase of oil and gas interests and $8,500 for purchase of fixed assets, compared to $2,500 in 2009 for purchase of fixed assets, an increase of $1,132,000.

Total assets as of December 31, 2010 were approximately $13,130,000 compared to total assets of $5,571,000 as of December 31, 2009.  Stockholder’s equity as of December 31, 2010 was approximately $12,885,000 compared to stockholders’ equity of $5,373,000 as of December 31, 2009. The increase in assets and stockholder’s equity was primarily related to common and preferred shares issued to Consultants.

As of December 31, 2010, we had current assets of approximately $2,995,000 including cash and cash equivalents of approximately $2,911,000. We had current liabilities of $245,000, resulting in working capital of approximately $2,749,000 as of December 31, 2010, as compared to approximately $5,362,000 for the same period ended 2009.

Pursuant to the PSC, covering three exploration blocks, Four, Five, and Dumre in the Republic of Albania, or the Concession Area, the Company has committed to minimum expenditures of $1,500,000 for the first exploration period of two years. Sky will provide a bank guarantee for $1,500,000 within 90 days of the effective date of the PSC to guarantee expenditures during the first exploration period. At the end of the First Exploration Period or the Second Exploration Pe1riod, Sky Petroleum has the right, subject to AKBN approval, to extend such period by one year.  In such a case, the duration of the second exploration period or the third exploration period shall be reduced to one year.  Sky Petroleum may terminate the PSC at the end of any exploration period. Sky Petroleum or an affiliated entity designated by Sky Petroleum will serve as operator under the Agreement. Sky Petroleum intends to use affiliated entities to hold and operate the Concession Area.

Since the Mubarek H2 well was completed in the second quarter of 2006, it has produced a total of 150,413 gross barrels as of December 31, 2010. Since the Mubarek K2-ST4 well was completed, it has produced a total of 149,471 gross barrels as of December 31, 2010.  Revenues provided from these wells were $85,570 for the year ended December 31, 2010 and $1,604,531 for the comparable period in 2009.  We expect no revenue from production in 2011 and will not have any revenue from our properties until we complete exploration and development programs, which may take a significant amount of time and investment.

On December 31, 2009, Sastaro received written notice from Buttes that Buttes had unilaterally and solely determined that the Mubarek Field had reached the end of its economic life. Buttes also notified Sastaro that the Concession Agreement, dated December 29, 1969, between the His Highness Sheikh Sultan bin Mohamed Al-Qassimi III, The Ruler of Sharjah, UAE and Buttes with respect to the Mubarek Field was terminated. Buttes stated that it handed over the Mubarek Field operations and facilities to representatives of His Highness Sheikh Sultan bin Mohamed Al-Qassimi III on December 28, 2009.  As a result, we have not had any cash flow from these wells since the second quarter of 2010; however we intend to pursue our rights under the agreement.

Over the next twelve months, we anticipate that our working capital requirements will increase.  Although we believe that existing capital will be sufficient to sustain operations, we anticipate that we may raise additional capital through equity, debt or other securities offerings during 2011 to fund exploration and working capital requirements.  Alternatively, we may explore joint venture, work-in or other arrangements for exploration, development or other activities on our projects

Our lack of operating history makes predictions of future operating results difficult to ascertain. Our prospects must be considered in light of the risks, expenses and difficulties frequently encountered by companies in their early stage of development, particularly companies searching for opportunities in the oil and gas industry. Such risks include, but are not limited to, our ability to secure a drilling rig, our ability to successfully drill for hydrocarbons, commodity price fluctuations, delays in drilling or bringing production, if any, on line, an evolving business model and unpredictable availability of qualified oil and gas exploration prospects and the management of growth. To address these risks we must, among other things, implement and successfully execute our business and development plan, successfully identify future drilling locations, continue to rely on qualified independent consultants, respond to competitive developments, and attract, retain and motivate qualified personnel. There can be no assurance that we will be successful in addressing such risks, and the failure to do so can have a material adverse effect on our business prospects, financial condition and results of operations.

Off-Balance Sheet Arrangements

We have no off-balance sheet arrangements.
 

22
 

 

Inflation

We do not believe that inflation has had a significant impact on our consolidated results of operations or financial condition.

Recent pronouncements

In January 2010, the FASB issued Accounting Standard Update (“ASU”) 2010-6, Improving Disclosures About Fair Value Measurements, which requires reporting entities to make new disclosures about recurring or nonrecurring fair-value measurements including significant transfers into and out of Level 1 and Level 2 fair-value measurements and information on purchases, sales, issuances, and settlements on a gross basis in the reconciliation of Level 3 fair-value measurements. ASU 2010-6 is effective for annual reporting periods beginning after December 15, 2009, except for Level 3 reconciliation disclosures which are effective for annual periods beginning after December 15, 2010. The adoption of ASU 2010-6 did not have a material impact on our consolidated financial statement disclosures.

On December 31, 2008, the SEC published the final rules and interpretations updating its oil and gas reporting requirements. Many of the revisions are updates to definitions in the existing oil and gas rules to make them consistent with the petroleum resource management system, which is a widely accepted standard for the management of petroleum resources that was developed by several industry organizations. Key revisions included changes to the pricing used to estimate reserves utilizing a 12-month average price rather than a single day spot price which eliminates the ability to utilize subsequent prices to the end of a reporting period, the ability to include nontraditional resources in reserves, the use of new technology for determining reserves, and permitting disclosure of probable and possible reserves. The SEC required companies to comply with the amended disclosure requirements for annual reports on Form 10-K for fiscal years ending on or after December 15, 2009. Earlier adoption was not permitted.

In January 2010, the FASB issued ASC Topic No. 932 to amend existing oil and gas reserve accounting and disclosure guidance (formerly FASB Staff Position No. 69), Extractive Activities-Oil and Gas, to align its requirements with the SEC’s Modernization of Oil and Gas Reporting rule. The significant revisions involve revised definitions of oil and gas producing activities, changing the pricing used to estimate reserves at period end to a twelve month arithmetic average of the first day of the month prices and additional disclosure requirements. In contrast to the SEC rule, the FASB does not permit the disclosure of probable and possible reserves in the supplemental oil and gas information in the notes to the financial statements. The amendments are effective for annual reporting periods ending on or after December 31, 2010. Application of the revised rules is prospective and companies are not required to change prior period presentation to conform to the amendments. Application of the amended guidance has only resulted in changes to the prices used to determine proved reserves at December 31, 2010 and 2009, respectively. The new guidelines have expanded the definition of proved undeveloped reserves that can be recorded from an economic producer. The opportunity to prove reasonable certainty for spacing areas located more than one direct development spacing area from economic producer did not impact the Company’s proved developed or undeveloped reserves.

The primary changes in the amended ASC Topic No. 932 are as follows:

Amending the definition of proved oil and gas reserves to indicate that entities must use the average, first-day-of-the-month price during the 12-month period before the ending date of the period covered by the report (the 12-month average price) rather than the year-end price, when estimating whether reserve quantities are economical to produce.

Change the price used to calculate the aggregate amount of (and changes in) future cash inflows related to the standardized measure of discounted future cash flows from the year-end price to the 12-month average price used in calculating proved reserves.

Adding to and amending other definitions in the Master Glossary used in estimating proved oil and gas reserves quantities (for example, reliable technology and reasonable certainty).

Requiring that an entity disclose separately information about reserve quantities and financial statement amounts for geographic areas that represent 15 percent or more of proved reserves. In addition, Topic No. 932 is amended to indicate that the quantity of reserves is not the only factor that should be considered in determining whether reserves are significant (that is, an entity would be required to consider all facts and circumstances in determining whether reserves are significant).

Clarifying that an entity’s equity method investments must be considered in determining whether it has significant oil- and gas producing activities.

 
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Critical Accounting Policies

Use of estimates

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting period. Actual results could differ significantly from those estimates.

Fair value of financial instruments

Fair value estimates discussed herein are based upon certain market assumptions and pertinent information available to management as of December 31, 2010 and 2009. The respective carrying value of certain on-balance sheet financial instruments approximated their fair values. These financial instruments include cash and cash equivalents and investments. Fair values were assumed to approximate carrying values for cash, cash equivalents, and accounts payable and accrued expenses because they are short term in nature and their carrying amounts approximate fair values as they are payable on demand.

The Company calculates the fair value of its assets and liabilities which qualify as financial instruments and includes this additional information in the notes to consolidated financial statements when the fair value is different than the carrying value of these financial instruments. The estimated fair value of accounts receivable, accounts payable and accrued liabilities approximate their carrying amounts due to the relatively short maturity of these instruments. None of these instruments are held for trading purposes.

ASC Topic 820, Fair Value Measurements and Disclosures, defines fair value, establishes a framework for measuring fair value in accordance with generally accepted accounting principles, and requires certain disclosures about fair value measurements. In general, fair values of financial instruments are based upon quoted market prices, where available (Level 1). If such quoted market prices are not available, fair value is based upon internally developed models that primarily use, as inputs, observable market-based parameters (Level 2). Valuation adjustments may be made to ensure that financial instruments are recorded at fair value. These adjustments may include amounts to reflect counterparty credit quality and the customer’s creditworthiness, among other things, as well as unobservable parameters (Level 3). Any such valuation adjustments are applied consistently over time.

Investment in oil and gas properties

The Company follows the full cost method of accounting for oil and gas operations whereby exploration and development expenditures are capitalized. Such costs may include geological and geophysical, drilling, equipment and technical consulting directly related to exploration and development activities. The aggregate of net capitalized costs and estimated future development costs is amortized using the units of production method based on estimated proved oil and gas reserves.

Advances for oil and gas interests are transferred to oil and gas properties as actual exploration and development expenditures are incurred.

Costs related to unproved properties and major development projects may be excluded from costs subject to depletion until proved reserves have been determined or their value is impaired. These properties are assessed periodically and any impairment is transferred to costs subject to depletion.

Under the full cost method of accounting, the net book value of oil and natural gas properties, less related deferred income taxes, may not exceed a calculated ceiling”. The ceiling limitation is the discounted estimated after-tax future net cash flows from proved oil and natural gas properties. In calculating future net cash flows, current prices and costs are generally held constant indefinitely. The net book value of oil and natural gas properties, less related deferred income taxes is compared to the ceiling on a quarterly and annual basis. Any excess of the net book value, less related deferred income taxes, is generally written off as an expense. Under rules and regulations of the SEC, all or a portion of the excess above the ceiling may not be written off if, subsequent to the end of the quarter or year but prior to the release of the financial results, prices have increased sufficiently that all or a portion of such excess above the ceiling would not have existed if the increased prices were used in the calculations.

As of December 31, 2009, the Company had accumulated impairment of $15,468,368 on the Mubarek Field wells as a result of the full cost ceiling test for the years 2006 through 2009. As of December 31, 2010, the net carrying value of the Company’s investment in these wells was $0.

As of December 31, 2010, the Company has incurred $10,115,220 in acquisition and development costs for oil and gas projects in Albania.  These costs, relate to the Production Sharing Contract with the Ministry of Economy, Trade and Energy of Albania.
 
 
24
 

 
 
Sales of proved and unproved properties are accounted for as an adjustment of capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved oil and natural gas reserves, in which case the gain or loss is recognized.

Revenue is recognized in the period in which title to the petroleum or natural gas transfers to the purchaser.

Income taxes

We follow the FASB’s new guidance issued within ASC Topic No. 740, Accounting for Income Taxes, for recording the provision for income taxes. Deferred tax assets and liabilities are computed based upon the difference between the financial statement and income tax basis of assets and liabilities using the enacted marginal tax rate applicable when the related asset or liability is expected to be realized or settled. Deferred income tax expenses or benefits are based on the changes in the asset or liability each period. If available evidence suggests that it is more likely than not that some portion or all of the deferred tax assets will not be realized, a valuation allowance is required to reduce the deferred tax assets to the amount that is more likely than not to be realized. Future changes in such valuation allowance are included in the provision for deferred income taxes in the period of change. Deferred income taxes may arise from temporary differences resulting from income and expense items reported for financial accounting and tax purposes in different periods. Deferred taxes are classified as current or non-current, depending on the classification of assets and liabilities to which they relate. Deferred taxes arising from temporary differences that are not related to an asset or liability are classified as current or non-current depending on the periods in which the temporary differences are expected to reverse.

Undistributed earnings of the Company’s foreign subsidiaries are considered to be indefinitely reinvested and, accordingly, no provision for U.S. federal income taxes has been provided thereon. Upon distribution of those earnings in the form of dividends or otherwise, the Company may be subject to both U.S. income taxes (subject to an adjustment for foreign tax credits) and withholding taxes payable to the foreign countries.

The Company’s wholly owned subsidiaries have prepared required foreign tax returns that were due for the years ended December 31, 2005, 2006, 2007 and 2008. An accrual totaling approximately $33,000 has been included for potential tax liabilities, penalties and interest which will be due upon filing the returns with the appropriate countries.

In 2006, the FASB issued new guidance within ASC Topic No. 740 Income Taxes which clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements. ASC Topic No. 740 also prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. This topic provides guidance on de-recognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. The Company adopted this topic as of January 1, 2007, as required.

The current Company policy classifies any interest recognized on an underpayment of income taxes as interest expense and classifies any statutory penalties recognized on a tax position taken as other general and administrative expense. There was no interest or other general and administrative expenses accrued or recognized related to income taxes for the year ended December 31, 2010 and 2009 respectively. The Company has not taken a tax position that would have a material effect on the financial statements or the effective tax rate for the year ended December 31, 2010 or during any prior years. It is determined not to be reasonably possible for the amounts of unrecognized tax benefits to significantly increase or decrease within the next 12 months.

Contractual Obligations

Leases

The Company rents office facilities in Austin, Texas on a month to month basis, totaling approximately $30,000.

The Company leases office facilities in Dubai, United Arab Emirates, under a two year operating lease agreement that expires on October 13, 2011, totaling approximately $93,000.

The Company leases office facilities in Tirana, Albania under a two year operating lease agreement that expires on October 31, 2012, totaling approximately $80,000.

Oil and Gas Properties Commitments and Contingencies

Mubarek Field Operations:

On December 31, 2009, Sastaro received written notice from Buttes that Buttes had unilaterally and solely determined that the Mubarek Field had reached the end of its economic life. Buttes also notified Sastaro that the Concession Agreement, dated December 29, 1969, between the His Highness Sheikh Sultan bin Mohamed Al-Qassimi III, The Ruler of Sharjah, UAE and Buttes with respect to the Mubarek Field was terminated. Buttes have stated that it handed over the Mubarek Field operations and facilities to representatives of His Highness Sheikh Sultan bin Mohamed Al-Qassimi III on December 28, 2009.
 
 
25
 

 
 
As a result of these events, Buttes notified Sastaro that the Participation Agreement between Sastaro and Buttes was terminated. Under the terms of the Participation Agreement, the Company, through Sastaro, contributed $25 million in drilling and completion costs related to two in-fill wells, H2 and K2-ST4, for the right for the Registrant to participate in a share of their future production revenue.

The Mubarek Field wells H2 and K2-ST4 continue to produce commercial amounts of oil, and the Company believes that there is significant residual value in H2 and K2-ST4. Consequently, the Company considers the Participation Agreement valid and in good standing.  Management is evaluating its rights under the Participation Agreement and will take any and all actions required to protect the interests of the Company, its shareholders and its investment in the Mubarek Field.

Production Sharing Contract related to Blocks Four, Five and Dumre in Albania:

Under the terms of the PSC, Sky Petroleum has agreed to undertake exploration work on the blocks during the following three exploration periods over the next seven years commencing on the effective date of the PSC.

First Exploration Period:

The First Exploration Period is an initial period of two years in which Sky Petroleum has agreed to undertake G&G, including but not limited to acquisition of technical data, interpretation of geological, geophysical and well data, and conducting regional geological and structural studies (mapping, balanced cross sections); seismic reprocessing and seismic acquisition, with the following minimum expenditure commitments:

   
Minimum Expenditure in USD
Minimum Work Program
 
  
G&G Evaluation1, (Minimum expenditures for G&G will be split $150,000 for blocks 4 & 5 and $50,000 for Dumre block.)
 
$
200,000
Seismic Reprocessing (2D)
   
50,000
Seismic Acquisition (2D)2 150 km (Seismic acquisition: seismic acquisition will be split 100km in blocks 4 & 5 and 50km in Dumre block.)
   
1,250,000
Total Commitment
 
1,500,000

Any additional exploration work in excess of the minimum amounts during any exploration period (whether G&G or exploration wells) may be credited against Sky Petroleum’s minimum work obligations in subsequent exploration periods.  If Sky Petroleum fails to complete the minimum work program, Sky Petroleum may elect to pay AKBN the minimum expenditure amount.

Second Exploration Period:

Provided that Sky Petroleum has completed the minimum First Exploration Period work program or paid AKBN the minimum expenditure amount, Sky Petroleum may elect to extend the exploration period into a Second Exploration Period of three years.  During the Second Exploration Period, Sky Petroleum will undertake G&G; seismic acquisition and an exploration drilling program with the following minimum expenditure commitments:

   
Minimum Expenditure in USD
Minimum Work Program
 
  
G&G Evaluation
 
$
150,000
Exploration Wells or 1 Exploration Well and 100km Seismic Acquisition1 (Either (a) drill one well in blocks 4 & 5 and another well in Dumre block or (b) drill one well in blocks 4 & 5 and acquire 100km seismic in Dumre block.  The well(s) shall be drilled to a minimum vertical depth of 2,000 meters or until it reaches the Carbonates of the Eocene or Cretaceous, whichever first occurs.)
   
2,500,000
Total Commitment
 
2,650,000


26
 

 

Third Exploration Period:

Provided that Sky Petroleum has completed the minimum Second Exploration Period work program or paid AKBN the minimum expenditure amount, if, as approved by the AKBN, there are special circumstances which require more time for the contractor to perform adequate exploration activity, Sky Petroleum may elect to extend the exploration period into a Third Exploration Period of two years.  During the Third Exploration Period, Sky Petroleum will undertake G&G; seismic acquisition and an exploration drilling program with the following minimum expenditure commitments:

   
Minimum Expenditure in USD
Minimum Work Program
 
  
G&G Evaluation
 
$
150,000
2 Exploration Wells or 1 – 2000m (Drill one well in blocks 4 & 5 and another well in Dumre block. The wells are to be drilled to a minimum vertical depth of 2,000 meters or until it reaches the Carbonates of the Eocene or Cretaceous, whichever first occurs.)
   
3,000,000
Total Commitment
 
3,150,000

At the end of the First Exploration Period or the Second Exploration Period, Sky Petroleum has the right, subject to AKBN approval, to extend such period by one year.  In such a case, the duration of the Second Exploration Period or the Third Exploration Period shall be reduced to one year.  Sky Petroleum may terminate the PSC at the end of any exploration period.

If during the exploration periods, Sky Petroleum discovers petroleum accumulations capable of commercial production within the Concession Area (a “Discovery Area”); it can submit to AKBN a development plan and commence development of the Discovery Area.  Sky Petroleum will have production rights of 25 years for each field (a “Production Area”) from the date of initial commercial production, which may be extended, at Sky Petroleum’s option, for successive periods of five years on the same conditions, subject to approval by AKBN, which approval shall not be unreasonably withheld or delayed.  Sky Petroleum and AKBN will share profits from any commercial production of oil (after cost recovery by Sky Petroleum) based on a sliding scale formula, in which Sky Petroleum’s share of profits will range from 96% to 100%.  All available production is subject to a 10% royalty tax and Sky Petroleum’s profits are subject to a 50% Albania tax on petroleum profits.

Sky Petroleum will relinquish to AKBN 25% of the Concession Area, as designated by Sky Petroleum, within 180 days after the end of each of the First Exploration Period and the Second Exploration Period and all remaining acreage of the Concession Area at the end of the Third Exploration Period, that is not then subject to a Discovery Area or in a Production Area.  Sky Petroleum will not be required to relinquish areas included in a Discovery Area or in a Production Area.

In addition, to the work program undertakings, Sky Petroleum has also agreed to the following:

Education and Training Program:  Sky Petroleum has agreed to allocate $100,000 for training and education during each year of the Exploration period.

Bonus Payment Obligations:  Sky Petroleum has agreed to pay AKBN the following bonus payments:

Signing Bonus:  $50,000 within 60 days of the effective date of the PSC, and which has been included in accrued liabilities as of December 31, 2010.

Production Bonuses:

$150,000 on start-up of production from the Contract Area
 
$250,000 when average daily crude oil production over any consecutive ninety-day period reaches fifteen thousand (15,000) Barrels of oil per day

$500,000 when average daily crude oil production over any consecutive ninety-day period reaches thirty thousand (30,000) Barrels of oil per day.

Bank Guarantee: On December 17, 2010, a copy of the document evidencing final approval of the Council of Ministers of the Republic of Albania was published in the Fletoren Zyrtare.  The PSC became effective 10 working days after publication of the document on January 3, 2011.  Sky Petroleum has agreed to provide a bank guarantee of $1,500,000 within 90 days of the effective date of the PSC in an amount to guarantee expenditures during the First Exploration Period.
 
27
 

 
 
Sky Petroleum or an affiliated entity designated by Sky Petroleum will serve as operator under the Agreement. Sky Petroleum intends to use affiliated entities to hold and operate the Concession Area.

Consulting Agreements:

On May 18, 2010, Sky Petroleum entered into a Consultant with Orsett Ventures (the “Consultant”).  Under the terms of the Agreement, Sky Petroleum retained Consultant as an independent consultant to use the Consultant’s experience, know-how, qualifications and expertise to acquire and negotiate the acquisition of oil and gas properties and projects in the Republic of Albania (“Territory”).  The term is from May 18, 2010 through April 30, 2011, unless extended by mutual agreement of the Company and the Consultant or unless earlier terminated.

First Amendment:

On June 29, 2010, Sky Petroleum entered into Amendment No. 1 to the Consultant Agreement.  Sky Petroleum entered into the PSC, which related to the exploration and development concessions contemplated in the First Qualifying Transaction, but not the existing oil field in the Territory known as Amonica.  As such, Sky Petroleum and the Consultant agreed to amend the compensation paid for the First Qualifying Transaction as follows:

Sky Petroleum agreed to pay the Consultant the following consulting fee in connection with the execution and delivery of the PSC:

A)
1,500,000 shares of common stock of the Company; and

B)
$700,000 in cash.

Sky Petroleum agreed to also pay the Consultant the following consulting fee in connection with the execution and delivery of the definitive agreements related to the acquisition of a designated producing oil and gas field in the Territory (the “Producing Field Transaction”):

A)
1,500,000 shares of common stock of the Company; and

B)
$300,000 in cash.

In July 2010, the Company paid the Consultant $700,000 related to the first qualifying transaction.  In addition, the fair market value of the 1,500,000 common shares ($480,000) has also been included as additional paid in capital as of December 31, 2010.  The consultant costs are included in the investment in oil and gas properties as of December 31, 2010.

Second Amendment:

On October 3, 2010, the Company executed a Second Amendment to the Consultant Agreement.  Pursuant to Amendment No. 2 to the Consultant Agreement, Sky Petroleum’s payment obligations to the Consultant were further amended to reflect the expanded nature and scope of the services provided by the Consultant to Sky Petroleum in order to provide what the Board of Directors of Sky Petroleum has determined, in negotiation with the Consultant, is fair market consideration for the additional value conferred on Sky Petroleum by the expanded nature and scope of such services.  Amendment No. 2 to the expanded nature and scope of the services provided to Sky Petroleum by the Consultant to include, in addition to those services provided by the Consultant under the Agreement, the following:

the Consultant will provide in-country and local support to assist Sky Petroleum with the acquisition, development and obtaining approvals for projects in the Republic of Albania;

the Consultant will make introductions to financial institutions and capital sources and provide support in capital raising transactions;

the Consultant will make introductions to strategic partners, third-party operators and local experts and vendors to assist in the acquisition, development and commercialization of oil and gas properties in the Republic of Albania; and

the Consultant will assist Sky Petroleum with strategic planning and project plans in connection with in the acquisition, development and commercialization of oil and gas properties in the Republic of Albania.

In consideration for expanding the nature and scope of the Consultant’s services under Amendment No. 2 to the Consulting Agreement, Sky Petroleum agreed to further amend the Agreement to provide for the acceleration of certain amounts due under the Agreement and for the payment of additional compensation as fair market consideration for the additional value conferred on Sky
 
 
28

 
Petroleum by the expanded nature and scope of the services provided by the Consultant.  Accordingly, the Agreement was amended and restated in Amendment No. 2 to provide for the following:

a.  
concurrent with the valid execution and delivery of Amendment No. 2 to the Agreement, Sky Petroleum’s Board of Directors designated 5,000,000 shares of Sky Petroleum’s authorized but unissued preferred shares as Series B Convertible Preferred Shares (the “Series B Preferred Shares”) and filed a certificate of designations (“Certificate of Designations”) with the Secretary of State of the State of Nevada in respect of the Series B Preferred Shares.  The Series B Preferred Shares shall be convertible into shares of common stock of Sky Petroleum (“Common Shares”) after a period of twelve months from the date of initial issuance at a ratio of 4.4 Common Shares for each Series B Preferred Share.  In addition to the twelve month restriction on conversion and such other terms as are normally associated with convertible preferred shares, the Series B Preferred Shares shall not be converted by the Consultant if after giving effect to such conversion the Consultant would in the aggregate beneficially own, or exercise control or direction over, that number of voting securities of Sky Petroleum which equals 4.99% or greater of the total issued and outstanding voting securities of Sky Petroleum during the ninety day period ending on the date of conversion (the “Beneficial Ownership Limitation”); provided, however, that the Consultant may waive the Beneficial Ownership Limitation by providing Sky Petroleum with sixty-one days notice of the Consultant’s desire to waive the Beneficial Ownership Limitation.

b.  
Sky Petroleum agreed to issue 3,863,636 Series B Preferred Shares and 1,500,000 Common Shares to the Consultant;

c.  
Sky Petroleum agreed to pay the Consultant the sum of $150,000; and

d.  
within five business days of the valid execution and delivery of the Second Qualifying Agreement, defined below, and the receipt of such regulatory and governmental approvals as may be required under applicable Albanian law, Sky Petroleum agreed to issue 1,136,364 Series B Preferred Shares and pay $150,000 to the Consultant.  The Second Qualifying Agreement is defined in amended and restated Schedule C to Amendment No. 2 to the Agreement as one or more definitive binding, written agreements entered into prior to April 30, 2011 that provide or provides for the Sky Petroleum’s privatization and acquisition of assets, rights, wells, concessions, rigs, storage facilities, equipment, licenses, permits, data and other assets of Albpetrol Sh.a (“Albpetrol”), and of properties, concessions, rights and permits for oil production (excluding Block 4, Block 5 and Block Dumre previously acquired by Sky Petroleum) as may be negotiated between Sky Petroleum and Albpetrol or between Sky Petroleum and the Ministry of Economy, Trade and Energy of the Republic of Albania (the “Second Qualifying Assets”); and (B) execution of definitive Production Sharing Agreements in the form mandated in the “Petroleum Law”, No.7746, date 28.07.1993 and the document “Albanian Legislation and the Framework for Petroleum Exploration and Production” related to the Second Qualifying Assets that vest all rights to the Second Qualifying Assets in Sky Petroleum.  We have not delivered payment under Amendment No. 2 pending final confirmation of the PSC.

On October 8, 2010, pursuant to the terms of the Consultant Agreement, the Company filed a Certificate of Designation with the Secretary of State for the State of Nevada to designate 5,000,000 shares of the Company’s preferred stock as shares of Series B Preferred Stock (the "Series B Preferred Shares”).

On December 3, 2010, following notification of approval by the Council of Ministers for the Republic of Albania the Company issued the following securities to the Consultant:

(a)       3,863,636 shares of Series B Preferred Stock and
(b)       1,500,000 shares of common stock.

During December 2010, the Company paid the Consultant $150,000 related to the additional services and issued the additional 1,500,000 shares ($690,000) and 3,863,636 Series B Preferred Shares ($7,820,000).  The Consultant’s costs are included (based on the fair market value of the securities) in the investment in oil and gas properties as of December 31, 2010.

As of December 31, 2010, we paid the Consultant a total of 3,000,000 common shares with a fair value of $1,170,000; total cash payments of $850,000, and a total of 3,863,363 Series B Preferred Shares with a value of $7,820,000. The total of these consultant costs of $9,840,000 are included in the investment in oil and gas properties totaling $10,115,220 as of December 31, 2010.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Not Applicable.


29
 

 
 
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of Sky Petroleum, Inc.

We have audited the accompanying consolidated balance sheets of Sky Petroleum, Inc. and subsidiaries, as of December 31, 2010 and 2009, and the related consolidated statements of operations, changes in stockholders’ equity, and cash flows for the years then ended. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. An audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Sky Petroleum, Inc. and subsidiaries, as of December 31, 2010 and 2009, and the results of their operations and their cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America.

       
/s/ WHITLEY PENN LLP
     
       
Dallas, Texas
March 28, 2011
     
 



30
 

 



Sky Petroleum, Inc.
Consolidated Balance Sheets

   
As of
December 31, 2010
   
As of
December 31, 2009
 
             
Assets
           
Current assets:
           
Cash and cash equivalents
  $ 2,911,464     $ 5,024,899  
Accounts receivable
          504,774  
Prepaids and other current assets
    83,435       30,752  
Total Current Assets
    2,994,899       5,560,425  
                 
Investment in oil and gas properties, net
    10,115,220       -  
Fixed assets, net
    9,278       2,472  
Deposits and other assets
    11,053       8,315  
                 
Total Assets
  $ 13,130,450     $ 5,571,212  
                 
Liabilities and Stockholders’ Equity
               
                 
Current liabilities:
               
Accounts payable and accrued liabilities
  $ 245,418     $ 198,598  
                 
Commitments and contingencies
               
                 
Stockholders’ equity:
               
Series A Preferred stock, $0.001 par value, 10,000,000 shares authorized, none issued and outstanding
           
 
               
Series B Preferred stock, no par value, 5,000,000 shares authorized, 3,863,636 issued and outstanding
    7,820,000        
Common Stock, $0.001 par value, 150,000,000 shares authorized, 61,868,709 and 58,793,709 shares issued and outstanding, respectively
    61,869       58,794  
Additional paid-in capital
    41,619,458       40,348,746  
Accumulated deficit
    (36,616,295 )     (35,034,926 )
Total Stockholders’ Equity
    12,885,032       5,372,614  
                 
Total Liabilities and Stockholders’ Equity
  $ 13,130,450     $ 5,571,212  
                 
 
 
The accompanying notes are an integral part of these consolidated financial statements




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Sky Petroleum, Inc.
Consolidated Statements of Operations

   
Year Ended December 31,
 
   
2010
   
2009
 
             
Oil revenues
  $ 85,570     $ 1,604,531  
   
               
Expenses: 
               
Lease operating expenses 
    33,806       120,204  
Depletion and depreciation  
    1,725       833,176  
Impairment of oil and gas properties
          230,825  
Consulting services 
    532,445       503,119  
Legal and Accounting
    385,647       207,087  
Travel
    288,619       64,633  
Stock based compensation
    103,787       5,629  
General and administrative 
    322,097       419,871  
Impairment of investment in non-affiliated entity
    -       1,000,000  
Total expenses 
    1,668,126       3,384,544  
   
               
Net operating loss 
    (1,582,556 )     (1,780,013 )
   
               
Interest income 
    1,187       5,699  
   
               
Net loss 
  $ (1,581,369 )   $ (1,774,314 )
   
               
Net loss per share - basic and diluted 
  $ (0.03 )   $ (0.03 )
Weighted average number of common shares outstanding - basic and diluted 
    59,703,962       58,793,709  
 
 
The accompanying notes are an integral part of these consolidated financial statements
 
 



32
 

 

Sky Petroleum, Inc.
Consolidated Statements of Changes in Stockholders’ Equity
Years Ended December 31, 2010 and 2009
 
   
Preferred
Series B Shares
   
Preferred
Series B Amount
   
Common
Shares
   
Common Shares
Amount
   
Additional
Paid-in
Capital
   
Accumulated Deficit
   
Total
Stockholders’ Equity
 
Balance at December 31, 2009
          $       58,793,709     $ 58,794     $ 40,343,117     $ (33,260,612 )   $ 7,141,299  
 Stock based compensation
                            5,629             5,629  
 Net loss
                                  (1,774,314 )     (1,774,314
Balance at December 31, 2009
                58,793,709       58,794       40,348,746       (35,034,926     5,372,614  
Issuance of Series B Preferred Stock
    3,863,636       7,820,000      
                        7,820,000  
Stock issued to Consultants
                3,000,000       3,000       1,167,000             1,170,000  
Stock issued to Directors
                75,000       75       54,675             54,750  
Stock based compensation
                            49,037             49,037  
    Net loss
                                  (1,581,369 )     (1,581,369 )
Balance at December 31, 2010
    3,863,636     $ 7,820,000       61,868,709     $ 61,869     $ 41,619,458     $ (36,616,295 )   $ 12,885,032  



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



33

 
 

 

Sky Petroleum, Inc.
Consolidated Statements of Cash Flows

   
Year Ended
December 31,
 
   
2010
   
2009
 
             
Cash flows from operating activities:
           
Net loss
  $ (1,581,369 )   $ (1,774,314 )
Adjustments to reconcile net loss to net cash used in operating activities:
               
Impairment of investment in non-affiliated entity
          1,000,000  
Stock based compensation
    103,787       5,629  
Depletion and depreciation
    1,725       833,176  
Impairment of oil and gas properties
          230,825  
Changes in operating assets and liabilities -
               
Accounts receivable
    504,774       (504,774
Inventory - oil in storage
          21,796  
Prepaids and other current assets
    (52,683 )     (30,752 )
Deposits and other assets
    (2,738 )     (4,106 )
Accounts payable and accrued liabilities
    46,819       7,631  
Net cash used in operating activities
    (979,685     (214,889 )
                 
Cash flows from investing activities:
               
Purchase of oil and gas interests
    (1,125,220 )      
Purchase of fixed assets
    (8,530 )     (2,472 )
Net cash used in investing activities
    (1,133,750 )     (2,472 )
                 
Net decrease in cash and cash equivalents
    (2,113,435 )     (217,361 )
Cash and cash equivalents at beginning of year
    5,024,899       5,242,260  
Cash and cash equivalents at end of year
  $ 2,911,464     $ 5,024,899  
                 
Supplemental disclosures:
               
Non-Cash Investing and Financing Activities:
               
Acquisition of oil and gas investment through issuance of 3,863,636 shares of Preferred Stock Series B
  $ 7,820,000     $  
Acquisition of oil and gas investment through issuance of 3,000,000 common shares
  $ 1,170,000     $  

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



34
 

 

Sky Petroleum, Inc.
Notes to Consolidated Financial Statements

Note 1 - Organization and Basis of Presentation

The Company was organized on August 22, 2002 under the laws of the State of Nevada, as The Flower Valet. On December 20, 2004, the Company amended its articles of incorporation to change its name to Seaside Explorations, Inc. Subsequently, on March 28, 2005 the Company changed its name to Sky Petroleum, Inc.

The Company is engaged in the exploration and development of oil and natural gas properties of others under arrangements in which we finance the costs in exchange for interests in the oil or natural gas revenue generated by the properties. Such arrangements are commonly referred to as farm-ins to us, or farm-outs by the property owners farming out to us.

In order to manage its international oil and gas operations, the Company established two corporations in Cyprus. Bekata Limited (“Bekata”), a wholly-owned subsidiary of Sky Petroleum, Inc. owns a 100% interest in Sastaro Limited, (“Sastaro”).

On June 24, 2010, Sky entered into a Production Sharing Contract (“PSC”) with the Ministry of Economy, Trade and Energy of Albania, acting through the National Agency of Natural Resources of Albania (“AKBN”).  The PSC grants Sky Petroleum exclusive rights to three exploration blocks (Block Four, Block Five and Block Dumre) in the Republic of Albania (the “Concession Area”). The Concession Area covers approximately 1.2 million acres, representing approximately 20% of the landmass of Albania. The PSC has a seven-year term with three exploration periods. Upon commercial discovery of gas, the agreement allows for development and production periods of 25 years plus extensions at the Company’s option.

On May 18, 2005, our wholly owned subsidiary Sastaro entered into a Participation Agreement with Buttes Gas and Oil Co. International Inc. (which we refer to as “Buttes”), a wholly-owned subsidiary of Crescent Petroleum Company International Limited (which we refer to as “Crescent”) for the financing of a drilling program in the Mubarek field. The field is an offshore region in a concession area surrounding Abu Musa Island in the Arabian Gulf. Under the terms of the Participation Agreement, the Company participated in a share of the future production revenue by contributing $25 million in drilling and completion costs related to two wells in an off-shore oil and gas project in the United Arab Emirates. The operator of the drilling program, Crescent completed the first well, Mubarek H2, during the second quarter of 2006. The second well, Mubarek K2-ST4, was completed on October 4, 2007. Since the Mubarek H2 well was completed it has produced a total of 150,413 gross barrels as of December 31, 2010. Since the Mubarek K2-ST4 well was completed, it has produced a total of 149,471 gross barrels as of December 31, 2010.

On December 31, 2009, Sastaro received written notice from Buttes that Buttes unilaterally and solely determined that the Mubarek Field had reached the end of its economic life. Buttes also notified Sastaro that the Concession Agreement, dated December 29, 1969, between the His Highness Sheikh Sultan bin Mohamed Al-Qassimi III, The Ruler of Sharjah, UAE and Buttes with respect to the Mubarek Field was terminated. Buttes have stated it handed over the Mubarek Field operations and facilities to representatives of His Highness Sheikh Sultan bin Mohamed Al-Qassimi III on December 28, 2009. Management is exercising its rights under the Participation Agreement and intends to take all actions required to protect our interests, our shareholders and our investment in the Mubarek Field.

Note 2 - Summary of Significant Accounting Policies

The consolidated financial statements included herein, presented on the accrual basis, in accordance with accounting principles generally accepted in the United States of America and stated in US dollars, have been prepared by the Company, pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”).

Basis of Consolidation

The accompanying financial statements present the consolidated accounts of the Company and its wholly owned subsidiaries, Bekata and Sastaro. All intercompany account balances and transactions have been eliminated.

Nature of Operations

The Company’s focus is on the acquisition, development and exploitation of long-lived oil and natural gas reserves and, to a lesser extent, exploration for new oil and natural gas reserves. The Company’s business activities are currently carried out in off-shore Sharjah, UAE, and in concession areas in Albania.
 

35
 

 

Investments

Investments in non-affiliated companies with a less than 20% ownership interest, no significant influence, and market prices are not readily available, are accounted for under the cost method.

Property and Equipment

Oil and natural gas properties:

The Company uses the full cost method of accounting for its oil and natural gas producing activities. Accordingly, all costs associated with acquisition, exploration, and development of oil and natural gas reserves, including directly related overhead costs, are capitalized. Management and service fees received under contractual arrangements, if any, are treated as reimbursement of costs, offsetting the costs incurred to provide those services.

Depletion is provided using the units-of-production method based upon estimates of proved oil and natural gas reserves with oil and natural gas production being converted to a common unit of measure based upon their relative energy content. Investments in unproved properties and major development projects are not amortized until proved reserves associated with the projects can be determined or until impairment occurs. If the results of an assessment indicate that the properties are impaired, the carrying value of the assets is reduced accordingly. Once the assessment of unproved properties is complete and when major development projects are evaluated, the costs previously excluded from amortization are transferred to the full cost pool and amortization begins.

Under the full cost method of accounting, the net book value of oil and natural gas properties, less related deferred income taxes, may not exceed a calculated “ceiling”. The ceiling limitation is the discounted estimated after-tax future net cash flows from proved oil and natural gas properties. In calculating future net cash flows, current prices and costs are generally held constant indefinitely. The net book value of oil and natural gas properties, less related deferred income taxes is compared to the ceiling on a quarterly and annual basis. Any excess of the net book value, less related deferred income taxes, is generally written off as an expense. Under rules and regulations of the SEC, all or a portion of the excess above the ceiling may not be written off if, subsequent to the end of the quarter or year but prior to the release of the financial results, prices have increased sufficiently that all or a portion of such excess above the ceiling would not have existed if the increased prices were used in the calculations.

As of December 31, 2009, the Company had accumulated impairment of $15,468,368 on the Mubarek Field wells as a result of the full cost ceiling test for the years 2006 through 2009. As of December 31, 2010, the net carrying value of the Company’s investment in these wells was $0.

As of December 31, 2010, the Company has incurred $10,115,220 in acquisition and development costs for oil and gas projects in Albania.  These costs relate to the Production Sharing Contract with the Ministry of Economy, Trade and Energy of Albania approved as of December 3, 2010.

Sales of proved and unproved properties are accounted for as an adjustment of capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved oil and natural gas reserves, in which case the gain or loss is recognized.

Other Property and Equipment:

Maintenance and repairs are charged to operations. Renewals and betterments are capitalized to the appropriate property and equipment accounts.

Upon retirement or disposition of assets other than oil and natural gas properties, the cost and related accumulated depreciation are removed from the accounts with the resulting gains or losses, if any, recognized in income. Depreciation of other property and equipment is computed using the straight-line method based on the estimated useful lives of the property and equipment.

Income Taxes

The Company accounts for federal income taxes using the liability method. Under the liability method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. Under the liability method, the effect on previously recorded deferred tax assets and liabilities resulting from a change in tax rates is recognized in operating results in the period in which the change is enacted.
 
 
36
 

 
 
The current Company policy classifies any interest recognized on an underpayment of income taxes as interest expense and classifies any statutory penalties recognized on a tax position taken as other general and administrative expense. There was no interest or other general and administrative expenses accrued or recognized related to income taxes for the year ended December 31, 2010 or 2009, respectively. The Company has not taken a tax position that would have a material effect on the financial statements or the effective tax rate for the year ended December 31, 2010 or during any prior years. It is determined not to be reasonably possible for the amounts of unrecognized tax benefits to significantly increase or decrease within the next 12 months.

Stock-Based Compensation

The Company measures all share-based payments, including grants of employee stock options, using a fair-value based method in accordance with the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic No. 505 and Topic No. 718 (formerly SFAS No. 123R) Share-Based Payments. The cost of services received in exchange for awards of equity instruments is recognized in the consolidated statement of operations based on the grant date fair value of those awards amortized over the requisite service period.

Basic and Diluted Net Loss Per Share

Net loss per share is presented in accordance FASB ASC Topic No. 260 (formerly SFAS No. 128) Earnings Per Share. Basic net loss per share is computed based on the weighted average shares of common stock outstanding for the period. Common stock equivalents which represent stock options have been excluded from the computation of diluted net loss per share at December 31, 2010 and 2009 as their effect is anti-dilutive. 

Use of Estimates in the Preparation of Consolidated Financial Statements

Preparation of the accompanying consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. The oil and natural gas reserve estimates, and the related future net cash flows derived from those reserves, are used in the determination of depletion expense and the full cost ceiling test and are inherently imprecise. Actual results could differ from those estimates.

Fair Value of Financial Instruments

The Company calculates the fair value of its assets and liabilities which qualify as financial instruments and includes this additional information in the notes to consolidated financial statements when the fair value is different than the carrying value of these financial instruments. The estimated fair value of accounts receivable, accounts payable and accrued liabilities approximate their carrying amounts due to the relatively short maturity of these instruments. None of these instruments are held for trading purposes.

ASC Topic 820, Fair Value Measurements and Disclosures, defines fair value, establishes a framework for measuring fair value in accordance with generally accepted accounting principles, and requires certain disclosures about fair value measurements. In general, fair values of financial instruments are based upon quoted market prices, where available (Level 1). If such quoted market prices are not available, fair value is based upon internally developed models that primarily use, as inputs, observable market-based parameters (Level 2). Valuation adjustments may be made to ensure that financial instruments are recorded at fair value. These adjustments may include amounts to reflect counterparty credit quality and the customer’s creditworthiness, among other things, as well as unobservable parameters (Level 3). Any such valuation adjustments are applied consistently over time.

Cash Equivalents

For purposes of the consolidated statements of cash flows, the Company considers all demand deposits, money market accounts and certificates of deposit purchased with an original maturity of three months or less to be cash equivalents.

Revenue Recognition

Oil and natural gas revenues are recorded using the sales method, whereby the Company recognizes oil and natural gas revenue based on the amount of oil and natural gas sold to purchasers. As of December 31, 2010 and 2009, the Company did not have any oil or natural gas imbalances recorded. The Company does not recognize revenues until they are realized or realizable and earned. Revenues are considered realized or realizable and earned when: (i) persuasive evidence of an arrangement exists; (ii) delivery has occurred or services have been rendered; (iii) the seller’s price to the buyer is fixed or determinable; and (iv) collectability is reasonably assured.
 
 
37
 

 
 
Reclassifications

Certain prior period amounts have been reclassified to conform to current period presentation.

Recent Accounting Pronouncements

In January 2010, the FASB issued Accounting Standard Update (“ASU”) 2010-6, Improving Disclosures About Fair Value Measurements, which requires reporting entities to make new disclosures about recurring or nonrecurring fair-value measurements including significant transfers into and out of Level 1 and Level 2 fair-value measurements and information on purchases, sales, issuances, and settlements on a gross basis in the reconciliation of Level 3 fair-value measurements. ASU 2010-6 is effective for annual reporting periods beginning after December 15, 2009, except for Level 3 reconciliation disclosures which are effective for annual periods beginning after December 15, 2010. The adoption of ASU 2010-6 did not have a material impact on our consolidated financial statement disclosures.

On December 31, 2008, the SEC published the final rules and interpretations updating its oil and gas reporting requirements. Many of the revisions are updates to definitions in the existing oil and gas rules to make them consistent with the petroleum resource management system, which is a widely accepted standard for the management of petroleum resources that was developed by several industry organizations. Key revisions included changes to the pricing used to estimate reserves utilizing a 12-month average price rather than a single day spot price which eliminates the ability to utilize subsequent prices to the end of a reporting period, the ability to include nontraditional resources in reserves, the use of new technology for determining reserves, and permitting disclosure of probable and possible reserves. The SEC required companies to comply with the amended disclosure requirements for annual reports on Form 10-K for fiscal years ending on or after December 15, 2009. Earlier adoption was not permitted.

In January 2010, the FASB issued ASC Topic No. 932 to amend existing oil and gas reserve accounting and disclosure guidance (formerly FASB Staff Position No. 69), Extractive Activities-Oil and Gas, to align its requirements with the SEC’s Modernization of Oil and Gas Reporting rule. The significant revisions involve revised definitions of oil and gas producing activities, changing the pricing used to estimate reserves at period end to a twelve month arithmetic average of the first day of the month prices and additional disclosure requirements. In contrast to the SEC rule, the FASB does not permit the disclosure of probable and possible reserves in the supplemental oil and gas information in the notes to the financial statements. The amendments are effective for annual reporting periods ending on or after December 31, 2010. Application of the revised rules is prospective and companies are not required to change prior period presentation to conform to the amendments. Application of the amended guidance has only resulted in changes to the prices used to determine proved reserves at December 31, 2010 and 2009, respectively. The new guidelines have expanded the definition of proved undeveloped reserves that can be recorded from an economic producer. The opportunity to prove reasonable certainty for spacing areas located more than one direct development spacing area from economic producer did not impact the Company’s proved developed or undeveloped reserves.

The primary changes in the amended ASC Topic No. 932 are as follows:

Amending the definition of proved oil and gas reserves to indicate that entities must use the average, first-day-of-the-month price during the 12-month period before the ending date of the period covered by the report (the 12-month average price) rather than the year-end price, when estimating whether reserve quantities are economical to produce.

Change the price used to calculate the aggregate amount of (and changes in) future cash inflows related to the standardized measure of discounted future cash flows from the year-end price to the 12-month average price used in calculating proved reserves.

Adding to and amending other definitions in the Master Glossary used in estimating proved oil and gas reserves quantities (for example, reliable technology and reasonable certainty).

Requiring that an entity disclose separately information about reserve quantities and financial statement amounts for geographic areas that represent 15 percent or more of proved reserves. In addition, Topic No. 932 is amended to indicate that the quantity of reserves is not the only factor that should be considered in determining whether reserves are significant (that is, an entity would be required to consider all facts and circumstances in determining whether reserves are significant).

Clarifying that an entity’s equity method investments must be considered in determining whether it has significant oil- and gas producing activities.

Note 3 - Investment in Oil and Gas Properties

Blocks Four, Five and Dumre in Albania:

On June 24, 2010, Sky Petroleum executed a PSC, covering three exploration blocks, Four, Five, and Dumre in the Republic of Albania totaling approximately 5,000 km2 (1.2 million acres) (the “Concession Area”), representing approximately 20% of the landmass of Albania. Under the terms of the PSC, Sky Petroleum has agreed to undertake exploration work on the blocks during the following three exploration periods over the next seven years commencing on the effective date of the PSC.
 
38
 

 
 
First Exploration Period: The first exploration period is an initial period of two years in which Sky Petroleum has agreed to undertake geological and geophysical (“G&G”) preparations, including but not limited to acquisition of technical data, interpretation of geological, geophysical and well data, and conducting regional geological and structural studies (mapping, balanced cross sections); seismic reprocessing and seismic acquisition, with minimum expenditure commitments totaling $1,500,000.

Second Exploration Period:  Provided that Sky Petroleum has completed the minimum first exploration period work program or paid AKBN the minimum expenditure amount, Sky Petroleum may elect to extend the exploration period into a second exploration period of three years.  During the second exploration period, Sky Petroleum will undertake G&G; seismic acquisition and an exploration drilling program with minimum expenditure commitments totaling $2,650,000.

Third Exploration Period:  Provided that Sky Petroleum has completed the minimum second exploration period work program or paid AKBN the minimum expenditure amount, if, as approved by the AKBN, there are special circumstances which require more time for the contractor to perform adequate exploration activity, Sky Petroleum may elect to extend the exploration period into a third exploration period of two years.  During the third exploration period, Sky Petroleum will undertake G&G; seismic acquisition and an exploration drilling program with minimum expenditure commitments totaling $3,150,000

At the end of the First Exploration Period or the Second Exploration Period, Sky Petroleum has the right, subject to AKBN approval, to extend such period by one year.  In such a case, the duration of the Second Exploration Period or the Third Exploration Period shall be reduced to one year.  Sky Petroleum may terminate the PSC at the end of any exploration period.

If during the exploration periods, Sky Petroleum discovers petroleum accumulations capable of commercial production within the Concession Area (a “Discovery Area”); it can submit to AKBN a development plan and commence development of the Discovery Area.  Sky Petroleum will have production rights of 25 years for each field (a “Production Area”) from the date of initial commercial production, which may be extended, at Sky Petroleum’s option, for successive periods of five years on the same conditions, subject to approval by AKBN, which approval shall not be unreasonably withheld or delayed.  Sky Petroleum and AKBN will share profits from any commercial production of oil (after cost recovery by Sky Petroleum) based on a sliding scale formula, in which Sky Petroleum’s share of profits will range from 96% to 100%.  All available production is subject to a 10% royalty tax and Sky Petroleum’s profits are subject to a 50% Albania tax on petroleum profits.

Sky Petroleum will relinquish to AKBN 25% of the Concession Area, as designated by Sky Petroleum, within 180 days after the end of each of the First Exploration Period and the Second Exploration Period and all remaining acreage of the Concession Area at the end of the Third Exploration Period, that is not then subject to a Discovery or in a Production Area.  Sky Petroleum will not be required to relinquish areas included in a Discovery Area or in Production Area.

In addition, to the work program undertakings, Sky Petroleum has also agreed to allocate $100,000 for training and education during each year of the Exploration period. Sky also paid a signing bonus of $50,000 within 60 days of the effective date of the PSC, and which has been included in accrued liabilities as of December 31, 2010.

The following production bonuses will also be due and payable as follows:

Production Bonuses:
 
$150,000 on start-up of production from the Contract Area
 
$250,000 when average daily crude oil production over any consecutive ninety-day period reaches fifteen thousand (15,000) Barrels of oil per day

$500,000 when average daily crude oil production over any consecutive ninety-day period reaches thirty thousand (30,000) Barrels of oil per day.

Bank Guarantee:  On December 17, 2010, a copy of the document evidencing final approval of the Council of Ministers of the Republic of Albania was published in the Fletoren Zyrtare.  The PSC became effective 10 working days after publication of the document on January 3, 2011.  Sky Petroleum has agreed to provide a bank guarantee within 90 days of the effective date of the PSC in an amount to guarantee expenditures during the first exploration period $1,500,000.

Sky Petroleum or an affiliated entity designated by Sky Petroleum will serve as operator under the Agreement. Sky Petroleum intends to use affiliated entities to hold and operate the Concession Area.
 
 
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Consulting Agreement:

On May 18, 2010, Sky Petroleum entered into a Consultant Agreement for Business Development in the Republic of Albania (the “Consultant Agreement”) with Orsett Ventures Inc., a British Virgin Islands company (the “Consultant”).  The Consultant Agreement was amended on June 29, 2010 (Amendment #1) and on October 8, 2010 (Amended #2). Under the terms of the Agreement, Sky Petroleum retained Consultant as an independent consultant to use Consultant’s experience, know-how, qualifications and expertise to acquire and negotiate the acquisition of oil and gas properties and projects in the Republic of Albania.  The term is from May 18, 2010 through April 30, 2011, unless extended by mutual agreement of the Parties or unless earlier terminated. The Consultant’s fees were due upon execution of first and second qualifying transactions.

First Qualifying Transaction

Pursuant to Amendment #1, Sky Petroleum agreed to pay the Consultant in connection with the execution and delivery of the PSC $700,000 and 1.5 million shares of common stock, all of which was paid and tendered, respectively as of December 31, 2010.

Pursuant to Amendment #2, Sky agreed to pay the Consultant for additional services, $150,000, an additional 1.5 million common stock; and 3,863,636 shares of newly designated Series B Preferred Stock.  Following notification of approval by the Council of Ministers for the Republic of Albania of the PSC, the Company issued the Preferred Series B Stock. As of December 31, 2010, all fees and common and preferred shares were paid and tendered.

The fair market value of the 3 million common shares of approximately $1,170,000, and the fair market value of the 3,863,636 shares issued for Preferred Series B Stock of $7,820,000 have been included in oil and gas investments as of December 31, 2010.  . The fair value of the preferred stock was determined using quoted market prices along with internally developed models that primarily use, as inputs, observable market-based parameters, and other valuation adjustments made to ensure that financial instruments are recorded at fair value.

Total consultant costs of $9,840,000 along with other payments related to the investment totaling $275,220 are included in the investment in oil and gas properties totaling $10,115,220 as of December 31, 2010.

The Company’s investment in the Albania exploration blocks as of December 31, 2010 was $10,115,220.  This investment consisted of acquisition costs related to the PSC totaling $50,000, and $850,000 for fees to consultants for locating and negotiating the Company’s investment in the Albania exploration blocks, and $225,220 for fees related to evaluations and assessments of the concession area.  In addition, 3 million shares of common stock with a fair value of $1,170,000, plus 3,863,636 Preferred Shares Series B with a value of $7,820,000, were issued to the Consultant for expertise provided to the Company in acquiring and negotiating the acquisition of oil and gas properties.

Mubarek Field Operations:

On May 18, 2005, the Company entered into a Participation Agreement with Buttes, whereby the Company provided cash in the amount of $25,000,000, to be used for drilling costs associated with two oil wells located in the Arabian Gulf in exchange for a variable percentage of future production revenue. Pursuant to the Participation Agreement, the Company provided capital to Buttes in developmental increments. Upon commencement of production, which occurred in May 2006, the Company was to receive a preferred 75% of combined production revenue until such time as the Company recouped its total investment, and thereafter an incremental decrease of production revenue to 40%, until the Company has recouped two times its initial investment, and thereafter at 9.2%.

As of June 30, 2008, Buttes incurred drilling costs totaling approximately $53,219,000, exceeding the original cost estimates and funding by the Company of $25,000,000, and thus reducing the Company’s preferred share of combined production revenue from 75% to 35.25% until such time as the Company has recouped its total investment, and thereafter an incremental decrease of production revenue to 18.84% until the Company has recouped two times its initial investment, and thereafter at 4.33%.

The Company’s operating costs are capped at $3.00 per barrel and royalty fees are 14.5% of gross production revenues under the Participation Agreement.

On December 31, 2009, Sastaro received written notice from Buttes that Buttes had unilaterally and solely determined that the Mubarek Field had reached the end of its economic life. Buttes also notified Sastaro that the Concession Agreement, dated December 29, 1969, between the His Highness Sheikh Sultan bin Mohamed Al-Qassimi III, The Ruler of Sharjah, UAE and Buttes with respect to the Mubarek Field was terminated. Buttes have stated that it handed over the Mubarek Field operations and facilities to representatives of His Highness Sheikh Sultan bin Mohamed Al-Qassimi III on December 28, 2009.
 
 
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Buttes have notified Sastaro that the Participation Agreement between Sastaro and Buttes is terminated. Under the terms of the Participation Agreement, the Registrant, through Sastaro, contributed $25 million in drilling and completion costs related to two in-fill wells, H2 and K2-ST4, for the right for the Registrant to participate in a share of their future production revenue.

As a result of these events, and as of December 31, 2009, the investment in the wells was impaired to zero.  There was one final lift of 1,521 barrels in April 2010, resulting in revenues of $85,570 for the year ended December 31, 2010.

As of December 31, 2010 and 2009, respectively, the Company's investment in the Mubarek field oil and gas properties was zero.

The Company incurred an impairment charge of $230,825, after recording depletion of $831,747 for the year ended December 31, 2009. As the investment in the wells was impaired to zero, the Company did not obtain estimated petroleum reserves as of December 31, 2010 or 2009.

As of December 31, 2010 and 2009, the Company’s investment in oil and gas properties related to the Mubarek wells consisted of:

   
2010
   
2009
 
Evaluated Properties:    
 
 
       
Mubarek K2-ST4 Well
  $ 13,173,901     $ 13,173,901  
                 
Mubarek H2 Well
    13,457,501       13,457,501  
                 
Accumulated Depletion
    (11,163,034 )     (11,163,034 )
                 
Impairment
    (15,468,368 )     (15,468,368 )
                 
Total
  $     $  

As of December 31, 2010 and 2009, the Company has capitalized drilling and completion costs incurred for the Mubarek H2 well of $13,457,501 and the Mubarek K2-ST4 well of $13,173,901. Based on the December 31, 2008 reserve report prepared by Energy Services Group Dubai (“ESG”) proven developed reserves, net to the Company’s interest were 30,301 barrels of oil. During the year ended December 31, 2009, the Company recorded depletion expense of $831,747, respectively. The depletion amortization rate per equivalent unit of production (bbls) was $35.07 for the year ended December 31, 2009.

There were no costs excluded from the impairment calculation at December 31, 2010 and 2009.

Note 4 - Revenue Entitlement Adjustment

On May 18, 2005, we announced that our wholly-owned subsidiary, Sastaro, entered into a Participation Agreement with Buttes. Under the terms of the Participation Agreement, Sastaro had the right to participate in a share of the future production revenue by contributing up to $25 million in drilling and completion costs related to two wells in an off-shore oil and gas project in the UAE. The project is located in the Ilam/Mishrif reservoir of the Mubarek Field area near Abu Musa Island in the Arabian Gulf, which we refer to as the Concession Area. The Participation Agreement does not grant Sastaro any interest in the Concession Area other than the right to receive a share of future production revenue.

The Participation Agreement obligated Sastaro to pay $25 million in drilling and completion costs related to two wells. As of March 31, 2006, Sastaro had paid Buttes the full $25 million commitment. Buttes have the responsibility for carrying out all drilling and completion work related to the wells. In addition, under the Participation Agreement, if Buttes decides to drill additional wells in the Concession Area, we will have the option to participate in these wells and, upon exercise of the option, will be obligated to pay 100% of the drilling and completion costs of any of these wells.

Under the Participation Agreement, if Buttes estimated that the drilling and completion costs of the second well increased the total drilling and completion costs of the two wells above $25 million, Sastaro would have the option, but not the obligation, to pay these additional costs. Upon exercising this option, Sastaro would become obligated to pay the total costs of the second well whether above or below Buttes’ estimate. As of December 31, 2008, Buttes reported that the drilling and completion costs for the Mubarek H2 and K2-ST4 wells totaled approximately $53 million.

Sastaro did not exercise its option to pay the additional costs as reported by Buttes and subsequently, Sastaro’s entitlement interest was retroactively decreased from 75% to 34.67%, starting with the first sales dated September 11, 2006 until October 31, 2008 when it increased to 35.32% as a result of a reduction in costs from proceeds received from the sale of unused equipment.
 
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Note 5 - Investment in Non-Affiliated Entity

In 2007, the Company acquired a minority stake in the development of an oilfield in the Komi Republic of the Russian Federation by acquiring a 3.9% interest, subject to dilution, in Pechora Energy through its UK parent company, Concorde Oil & Gas Plc. (which we refer to as “Concorde”). This acquisition was essentially a carried interest as the Company will not be required to contribute additional funds as Concorde intends to fund the field development through debt and production revenues rather than further shareholder equity. In addition, as the market prices are not readily available, and management does not have significant influence, the investment was accounted for as a cost method investment.

On December 31, 2010, Concorde entered into binding agreements with its majority shareholder, Kuwait Energy Company (“KEC”), under which KEC will acquire Concorde’s principal operating subsidiaries, Pechora Energy Company and all other subsidiaries in return for shares of KEC and contingent earn-out notes, subject to the fulfillment of certain future operating conditions. This transaction is due to Concorde’s pre-tax loss of $30 million for the year ended March 31, 2009, along with other economic conditions, and the need for additional capital. The completion of this transaction is subject to a number of conditions, including regulatory consents, bank consent, and approval of KEC shareholders. Because KEC is a private company and related share information is not available, the market value of the proposed shares is not readily available. In addition, the Company does not possess the required information to determine a reasonable amount of shares to be obtained and potential earn-out note repayments without incurring excessive costs.

Evidence of loss in value that might indicate impairment of investments in companies is assessed to determine if such evidence represents a loss in value of the Company’s investment that is other than temporary. Examples of key indicators include a history of operating losses, negative earnings and cash flow outlook, and the financial condition and prospects for the investee’s business segment or geographic region. If evidence of another than temporary loss in fair value below carrying amount is determined, impairment is recognized. In the absence of market prices for the investment, discounted cash flows are used to assess fair value. As the Company will more likely than not be required to sell the securities in order to recoup its investment, an impairment loss of $1 million was recorded in operations for the year ended December 31, 2009.

Note 6 - Stockholders’ Equity

Preferred Stock

We have authorized 10 million shares of $0.001 par value Series A Preferred Stock. There were no shares of Series A Preferred Stock outstanding as of December 31, 2010 and 2009, respectively.

On October 8, 2010, pursuant to the terms of the Consultant Agreement, dated May 18, 2010, as amended June 29, 2010 and October 3, 2010, by and between the Company and the Consultant, the Company filed a Certificate of Designation with the Secretary of State for the State of Nevada to designate 5,000,000 shares of the Company’s preferred stock as shares of Series B Preferred Stock (the "Series B Preferred Shares").  

The Series B Preferred Shares have the following preferences, qualifications, rights, and restrictions:

Series B Preferred Shares shall not be entitled to receive preference or priority to any cash dividend on the Common Shares.  In event of a dividend, holders of Series B Preferred Shares shall be entitled to a proportionate share of any such dividend as though such holders of the Series B Preferred Shares were the holders of the number of Common Shares or other capital stock of the Company into which such holders’ Series B Preferred Shares are convertible as of the record date fixed for the determination of the holders of Common Shares entitled to receive such dividend.

Series B Preferred Shares shall have no liquidation preference in the event of any liquidation, dissolution or winding up of the Company, whether voluntary or involuntary.

Series B Preferred Shares will be non-voting, except with respect to amendments of the Certificate of Designation that adversely affect the rights of the holders of the Series B Preferred Shares.

Each Series B Preferred Share shall be convertible into 4.4 Common Shares (as adjusted for stock splits, reverse stock splits, stock dividends, stock reclassifications or stock reorganizations of the Common Shares).

Series B Preferred Shares shall not be converted by any holder, in whole or in part and the Company shall not give effect to any such conversion of Series B Preferred Shares for a period of twelve (12) months from the date of initial issuance.
 
 
42
 

 


 
Series B Preferred Shares shall not be converted by any holder, in whole or in part, and Company shall not give effect to any such conversion of Series B Preferred Shares, if, after giving effect to such conversion, the holder, together with any affiliate (including any person or company acting jointly or in concert with such holder), would in the aggregate beneficially own, or exercise control or direction over, that number of voting securities of Company which is 4.99% or greater of the total issued and outstanding voting securities of the Company during the ninety day period ending on the date of conversion, immediately after giving effect to such exercise (the “Beneficial Ownership Limitation”); provided, however, that upon any holder of Series B Preferred Shares providing the Company with sixty-one (61) days notice (the “Waiver Notice”) that such holder would like to waive the Beneficial Ownership Limitation, the Beneficial Ownership Limitation will be of no force or effect with regard to all or a portion of the Series B Preferred Shares as referenced in the Waiver Notice.

Series B Preferred Shares shall contain customary anti-dilution provisions in the event of any stock split, stock dividend, capital reorganization or reclassification of the capital stock of Company.

In connection with the Series B designation and the Consultant Agreement, the Company issued 3,863,636 shares, with a fair value of $7,820,000. These shares were issued to the Consultant for expertise provided to the Company in acquiring and negotiating the acquisition of oil and gas properties in Albania.

As of December 31, 2010, 3,863,636 shares of Series B Preferred Stock were outstanding.

Common Stock and Stock Options

On July 26, 2005, the Company adopted the Sky Petroleum, Inc. Non-U.S. Stock Option Plan (the “Non-U.S. Plan”), effective as of April 1, 2005. The Non-U.S. Plan authorizes the issuance of stock options to acquire up to 10% of the Company’s issued and outstanding shares of common stock.

On August 25, 2005, the Company adopted the Sky Petroleum, Inc. 2005 U.S. Stock Incentive Plan (the “U.S. Plan”). The U.S. Plan authorizes the issuance of stock options and other awards to acquire up to a maximum of 3,321,600 shares of the Company’s common stock (less the number of shares issuable upon exercise of options granted by the Company under all other stock incentive plans on the date of any grant under the U.S. Plan). The U.S. Plan provides for the grant of incentive stock options (within the meaning of Section 422 of the Internal Revenue Code of 1986, as amended), options that are not incentive stock options, stock appreciation rights and various other stock-based grants.

On June 29, 2010, the Company issued 450,000 stock options under the Non-U.S. Plan and 200,000 incentive stock options under the U.S. Plan.  The options are exercisable at $0.18 per share, with vesting over the next three years, and are valued at $69,684 and $31,316, respectively.    On August 17, 2010 and October 6, 2010, the Company issued 150,000 and 300,000 stock options respectively, under the Non-U.S. Plan to two directors exercisable at $0.50 and $.85, respectively, per share with vesting over the next three years with a total value of $314,234.  In addition, the directors were issued 25,000 and 50,000, respectively, common shares valued at $12,250 and $42,500, respectively based on the quoted market price at date of issuance.

For the years ended December 31, 2010 and 2009, the Company recorded $103,787 and $5,629, respectively, of compensation expense based on its use of the Black Scholes model to estimate the grant-date fair value of these stock option awards. No options were exercised during the years ended December 31, 2010 or 2009 therefore, the intrinsic value of options exercised during 2010 and 2009 is $0. Compensation expense is based upon straight-line amortization of the grant-date fair value over the vesting period of the underlying stock option. In accordance with ASC Topic No. 718 and No. 505, the fair value of each stock option grant was estimated on the date of the grant, using the Black-Scholes option-pricing model.

The 2010 stock options fair value was determined using the following attributes and assumptions for each separate issuance: share prices ranging from $0.18 to $0.85, risk-free interest rates of approximately 1.77% to 2.1%, expected dividend yields of 0%, expected life between 4.5 and 6 years, and expected volatility of 186% to 203%.  The Company estimates forfeitures based on historical experience. As of December 31, 2010, there was $366,198 of unrecognized compensation expenses related to non-vested stock option agreements.
 
 
43
 

 

A summary of stock options outstanding as of December 31, 2010, is as follows:

Shares Underlying Options Outstanding
   
Shares Underlying Options Exercisable
 
Range of
Exercise Prices
   
Shares
Underlying
Options
Outstanding
   
Weighted
Average
Remaining
Contractual
Life (Years)
   
Weighted
Average
Exercise
Price
   
Shares
Underlying
Options
Exercisable
   
Weighted
Average
Exercise
Price
 
$
0.18
     
650,000
     
7.42
   
$
0.18
     
   
$
 
$
0.50
     
300,000
     
6.11
   
$
0.50
     
50,000
   
$
0.50
 
$
0.85
     
300,000
     
6.77
   
$
0.85
     
–-
   
$
 
$
1.00
     
400,000
     
1.88
   
$
1.00
     
400,000
   
$
1.00
 
$
1.29 - $1.88
     
800,000
     
4.03
   
$
1.44
     
800,000
   
$
1.44
 

The aggregate intrinsic value of exercisable options as of December 31, 2010 is $0.  The aggregate intrinsic value of options outstanding as of December 31, 2010 is $169,000.

The following is a summary of stock option activity for the year ended December 31, 2010 and 2009:

   
Number
Of Shares
   
Weighted
Average
Exercise Price
   
Weighted Average
Remaining Contract Life (Years)
 
Balance, December 31, 2008
   
1,699,999
   
$
1.19
       
Options cancelled
   
(499,999
)
   
.93
       
Options granted
   
150,000
     
.50
       
Options exercised
   
     
       
Balance, December 31, 2009
   
1,350,000
     
1.20
       
Options cancelled
   
     
       
Options granted
   
1,100,000
     
.41
       
Options exercised
   
     
       
Balance, December 31, 2010
   
2,450,000
   
$
.85
     
5.17
 
                         
Exercisable, December 31, 2010
   
1,250,000
   
$
1.26
     
3.40
 

Note 7 - Income Taxes

For the years ended December 31, 2010 and 2009, the Company had net operating losses and, accordingly, no provision for income taxes has been recorded. In addition, no benefit for income taxes has been recorded due to the uncertainty of the realization of any tax assets. At December 31, 2010, the Company has accumulated operating losses totaling approximately $31 million. The net operating loss carry forwards will begin to expire in 2019 if not utilized. The Company has recorded net operating losses in each year since its inception through December 31, 2010. Based upon all available objective evidence, including the Company’s loss history, management believes it is more likely than not that the net deferred assets will not be fully realized. Therefore, the Company has provided a valuation allowance against its deferred tax assets at December 31, 2010 and 2009.

Non-current deferred tax assets were as follows for the date indicated:

 
December 31,
 
 
2010
 
2009
 
Net operating losses
  $ 10,751,770     $ 10,216,740  
Impairment of investment     350,000        350,000   
Less: valuation allowance
    (11,101,770 )     (10,566,740 )
Net non-current deferred tax asset
  $     $  

All of the Company’s current oil and gas activities are located offshore off the coast of Sharjah, UAE and in Albania and there are no income taxes due as no earnings or dividends were distributed or repatriated.

Undistributed earnings of the Company’s foreign subsidiaries are considered to be indefinitely reinvested and, accordingly, no provision for U.S. federal income taxes has been provided thereon. Upon distribution of those earnings in the form of dividends or otherwise, the Company may be subject to both U.S. income taxes (subject to an adjustment for foreign tax credits) and withholding taxes payable to the foreign countries.
 
The Company’s wholly owned subsidiaries have prepared the required foreign tax returns due for the years ended December 31, 2005 through December 31, 2008. No material tax liability was estimated. Management has engaged qualified firms to identify and prepare delinquent foreign tax returns for filing for the years ended 2010 and 2009, respectively. The Company believes amounts due, if any, would not be material.
 
 
44
 

 
 
Reconciliation between the income tax benefit determined by applying the applicable Federal statutory income tax rate to the pre-tax loss is as follows for the period indicated:

   
Year Ended December 31,
 
   
2010
   
2009
 
Tax benefit at statutory income tax rate
  $ (553,479 )   $ (621,010 )
Stock based compensation
    12,714       1,970  
Meals and entertainment
    5,735       2,404  
Change in valuation allowance
    535,030       616,636  
Tax benefit reported
  $     $  

Note 8 – Commitments and Contingencies

Leases

The Company leases office facilities under operating lease agreements that expire on October 13, 2011 and October 31, 2012, respectively. Rent payments due under the leases for the next year are $81,821 and $33,129 for the year ended December 31, 2012. The office leases are on a month to month cancellable basis. Total rent expense was $78,517 in 2010, and $56,394 in 2009.

Oil and Gas Properties Commitments and Contingencies

Mubarek Field Operations:

On December 31, 2010, Sastaro received written notice from Buttes that Buttes had unilaterally and solely determined that the Mubarek Field had reached the end of its economic life. Buttes also notified Sastaro that the Concession Agreement, dated December 29, 1969, between the His Highness Sheikh Sultan bin Mohamed Al-Qassimi III, The Ruler of Sharjah, UAE and Buttes with respect to the Mubarek Field was terminated. Buttes have stated that it handed over the Mubarek Field operations and facilities to representatives of His Highness Sheikh Sultan bin Mohamed Al-Qassimi III on December 28, 2009.

As a result of these events, Buttes notified Sastaro that the Participation Agreement between Sastaro and Buttes is terminated. Under the terms of the Participation Agreement, the Company, through Sastaro, contributed $25 million in drilling and completion costs related to two in-fill wells, H2 and K2-ST4, for the right for the Registrant to participate in a share of their future production revenue.

The Mubarek Field wells H2 and K2-ST4 continue to produce commercial amounts of oil, and the Company believes that there is significant residual value in H2 and K2-ST4. Consequently, the Company considers the Participation Agreement valid and in good standing.

Management is evaluating its rights under the Participation Agreement and will take any and all actions required to protect the interests of the Company, its shareholders and its investment in the Mubarek Field.

Production Sharing Contract with the Ministry of Economy, Trade and Energy of Albania:

On June 24, 2010, Sky entered into a PSC with the Ministry of Economy, Trade and Energy of Albania, acting through the National Agency of Natural Resources of Albania.  The PSC grants Sky Petroleum exclusive rights to three exploration blocks (Block Four, Block Five and Block Dumre) in the Republic of Albania (the “Concession Area”). The Concession Area covers approximately 1.2 million acres, representing approximately 20% of the landmass of Albania. The PSC has a seven-year term with three exploration periods. Upon commercial discovery of gas, the agreement allows for development and production periods of 25 years plus extensions at the Company’s option. To date, there have been more than ten identified prospects including three significant evaluation wells in each block: Palokastra well Block Four, Kanina well in Block Five, and a Dumre well.

First Exploration Period: The first exploration period is an initial period of two years in which Sky Petroleum has agreed to undertake G&G, including but not limited to acquisition of technical data, interpretation of geological, geophysical and well data, and conducting regional geological and structural studies (mapping, balanced cross sections); seismic reprocessing and seismic acquisition, with minimum expenditure commitments totaling $1,500,000.

Second Exploration Period:  Provided that Sky Petroleum has completed the minimum first exploration period work program or paid AKBN the minimum expenditure amount, Sky Petroleum may elect to extend the exploration period into a second exploration period of three years.  During the second exploration period, Sky Petroleum will undertake G&G; seismic acquisition and an exploration drilling program with minimum expenditure commitments totaling $2,650,000.
 
 
45
 

 
 
At the end of the first or second exploration period, Sky Petroleum shall have the right, subject to AKBN approval, to extend such periods by one year, reducing the later periods by one year.

Third Exploration Period:  Provided that Sky Petroleum has completed the minimum second exploration period work program or paid AKBN the minimum expenditure amount, if, as approved by the AKBN, there are special circumstances which require more time for the contractor to perform adequate exploration activity, Sky Petroleum may elect to extend the exploration period into a third exploration period of two years.  During the third exploration period, Sky Petroleum will undertake G&G; seismic acquisition and an exploration drilling program with minimum expenditure commitments totaling $3,150,000.

If during the exploration periods, Sky Petroleum discovers petroleum accumulations capable of commercial production within the Concession Area (a “Discovery Area”); it can submit to AKBN a development plan and commence development of the Discovery Area.  Sky Petroleum will have production rights of 25 years for each field (a “Production Area”) from the date of initial commercial production, which may be extended, at Sky Petroleum’s option, for successive periods of five years on the same conditions, subject to approval by AKBN, which approval shall not be unreasonably withheld or delayed.  Sky Petroleum and AKBN will share profits from any commercial production of oil (after cost recovery by Sky Petroleum) based on a sliding scale formula, in which Sky Petroleum’s share of profits will range from 96% to 100%.  All available production is subject to a 10% royalty tax and Sky Petroleum’s profits are subject to a 50% Albania tax on petroleum profits.

Sky Petroleum will relinquish to AKBN 25% of the Concession Area, as designated by Sky Petroleum, within 180 days after the end of each of the First Exploration Period and the Second Exploration Period and all remaining acreage of the Concession Area at the end of the Third Exploration Period, that is not then subject to a Discovery or in a Production Area.  Sky Petroleum will not be required to relinquish areas included in a Discovery Area or in Production Area.

Sky Petroleum or an affiliated entity designated by Sky Petroleum will serve as operator under the Agreement. Sky Petroleum intends to use affiliated entities to hold and operate the Concession Area. Sky Petroleum organized a Cayman Island corporation to hold and operate the Concession Areas.

In addition, to the work program undertakings, Sky Petroleum has also agreed to the following:

Education and Training Program:  Sky Petroleum has agreed to allocate $100,000 for training and education during each year of the Exploration period.

Production Bonuses:
 
$150,000 on start-up of production from the Contract Area
 
$250,000 when average daily crude oil production over any consecutive ninety-day period reaches fifteen thousand (15,000) Barrels of oil per day

$500,000 when average daily crude oil production over any consecutive ninety-day period reaches thirty thousand (30,000) Barrels of oil per day.

Bank Guarantee: On December 17, 2010, a copy of the document evidencing final approval of the Council of Ministers of the Republic of Albania was published in the Fletoren Zyrtare.  The PSC became effective 10 working days after publication of the document on January 3, 2011.  Sky Petroleum has agreed to provide a bank guarantee of $1,500,000 within 90 days of the effective date of the PSC in an amount to guarantee expenditures during the First Exploration Period.

Consulting Agreements:

On October 8, 2010, pursuant to the terms of the Consultant Agreement, dated May 18, 2010, as amended June 29, 2010 and October 3, 2010, by and between the Company and the Consultant, the Company filed a Certificate of Designation with the Secretary of State for the State of Nevada to designate 5,000,000 shares of the Company’s preferred stock as shares of Series B Preferred Stock (the "Series B Preferred Shares").  As of December 31, 2010, 3,386,636 of Series B shares have been issued related to the execution of the first qualifying transaction.

Within five business days of the valid execution and delivery of the Second Qualifying Agreement, Sky Petroleum agreed to issue an additional 1,136,364 Series B Preferred Shares and pay $150,000 to the Consultant.  The Second Qualifying Agreement is defined in amended and restated Schedule C to Amendment No. 2 to the Consultant Agreement. The agreement provides for  privatization and acquisition of assets, rights, wells, concessions, rigs, storage facilities, equipment, licenses, permits, data and other assets of Albpetrol Sh.a (“Albpetrol”), and of properties, concessions, rights and permits for oil production (excluding Block 4, Block 5 and Block Dumre
 
 
46


 
previously acquired by Sky Petroleum) as may be negotiated between Sky Petroleum and Albpetrol or between Sky Petroleum and the Ministry of Economy, Trade and Energy of the Republic of Albania (the “Second Qualifying Assets”); and execution of definitive Production Sharing Agreements in the form mandated in the “Petroleum Law”, No.7746, date 28.07.1993 and the document “Albanian Legislation and the Framework for Petroleum Exploration and Production” related to the Second Qualifying Assets that vest all rights to the Second Qualifying Assets in Sky Petroleum.  

Note 9 - Subsequent Events

On February 17, 2011, the Company incorporated Sky Petroleum (Albania) Inc., a Cayman Islands corporation and qualified branch in Albania, for the purposes of holding and operating the Company’s interests in the Concession Area in Albania.  Sky Petroleum (Albania) Inc. is a wholly-owned subsidiary of Sky Petroleum, Inc.

Note 10 - Supplemental Financial Information for Oil and Gas Producing Activities

As of December 31, 2010, the Company adopted the revisions to authoritative guidance related to oil and gas exploration and production activities that aligned the reserve estimation and disclosure requirements with the requirements of the SEC Modernization of Oil and Gas Reporting rule, which the Company also adopted. The new SEC rules require companies to value their year-end reserves using an un-weighted arithmetic average of the first day of the month oil and gas prices for each month within the twelve month period prior to the end of the reporting period.

In January 2010, the FASB issued ASC Topic No. 932 to amend existing oil and gas reserve accounting and disclosure guidance to align its requirements with the SEC’s Modernization of Oil and Gas Reporting rule. The significant revisions involve revised definitions of oil and gas producing activities, changing the pricing used to estimate reserves at period end to a twelve month arithmetic average of the first day of the month prices and additional disclosure requirements. In contrast to the SEC rule, the FASB does not permit the disclosure of probable and possible reserves in the supplemental oil and gas information in the notes to the financial statements. The amendments are effective for annual reporting periods ending on or after December 31, 2010. Application of the revised rules is prospective and companies are not required to change prior period presentation to conform to the amendments. Application of the amended guidance has only resulted in changes to the prices used to determine proved reserves at December 31, 2010 and 2009, respectively. The new guidelines have expanded the definition of proved undeveloped reserves that can be recorded from an economic producer. The opportunity to prove reasonable certainty for spacing areas located more than one direct development spacing area from economic producer did not impact the Company’s proved developed or undeveloped reserves.

The Company follows the guidelines prescribed in ASC Topic No. 932 for computing a standardized measure of future net cash flows and changes therein relating to estimated proved reserves. Future cash inflows and future production and development costs are determined by applying prices and costs, including transportation, quality, and basis differentials, to the year-end estimated quantities of oil and gas to be produced in the future. The resulting future net cash flows are reduced to present value amounts by applying a ten percent annual discount factor. Future operating costs are determined based on estimates of expenditures to be incurred in producing the proved oil and gas reserves in place at the end of the period using year-end costs and assuming continuation of existing economic conditions, plus Company overhead incurred. Future development costs are determined based on estimates of capital expenditures to be incurred in developing proved oil and gas reserves.

The assumptions used to compute the standardized measure are those prescribed by the FASB and the SEC. These assumptions do not necessarily reflect the Company’s expectations of actual revenues to be derived from those reserves, nor their present value. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these reserve quantity estimates are the basis for the valuation process. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimates of established proved producing oil and gas properties. Accordingly, these estimates are expected to change as future information becomes available.

The were no producing wells as of December 31, 2010, related to the Blocks Four, Five and Dumre in Albania.
 
Mubarek Field Operations:

The Company’s operations are directly related to oil and gas producing activities located offshore in the Arabian Gulf off of the coast of Sharjah, UAE.

Our proved oil reserves have been estimated by petroleum reserve engineers in Dubai as of December 31, 2008, whom were affiliated with the Company through a mutual director until May 2008.
 
 
47
 

 
 
On December 31, 2009, Sastaro received written notice from Buttes that Buttes had unilaterally and solely determined that the Mubarek Field had reached the end of its economic life. Buttes also notified Sastaro that the Concession Agreement, dated December 29, 1969, between the His Highness Sheikh Sultan bin Mohamed Al-Qassimi III, The Ruler of Sharjah, UAE and Buttes with respect to the Mubarek Field was terminated. Buttes have stated that it handed over the Mubarek Field operations and facilities to representatives of His Highness Sheikh Sultan bin Mohamed Al-Qassimi III on December 28, 2009.

As a result of these events the investment in the wells was impaired to zero, and therefore, the Company did not obtain estimated petroleum reserves as of December 31, 2010.

Capitalized Costs Relating to Oil and Gas Producing Activities:
   
2010
   
2009
 
Evaluated Properties:    
 
 
       
Mubarek K2-ST4 Well
  $ 13,173,901     $ 13,173,901  
                 
Mubarek H2 Well
    13,457,501       13,457,501  
                 
Accumulated Depletion
    (11,163,034 )     (11,163,034 )
                 
Impairment
    (15,468,368 )     (15,468,368 )
                 
Total
  $     $  

Costs Incurred in Oil and Gas Producing Activities:

For the Years Ended December 31:
 
2010
   
2009
 
Acquisition of proved properties
        $  
Acquisition of unproved properties-Albania project
   $ 10,115,220        
Development costs
           
Exploration costs
           
                 
Total Costs Incurred
  $ 10,115,220     $  

Results of Operations from Oil and Gas Producing Activities:

   
Year Ended
December 31,
 
   
2010
   
2009
 
Oil and gas revenues-Mubarek Field
  $ 85,570     $ 1,604,531  
Production costs-Mubarek Field
    (33,806 )     (120,204 )
Exploration expenses
           
Depletion and depreciation
          (831,747 )
Impairment
          (230,825 )
Results of oil and gas producing operations before income taxes
    51,764       421,755  
Provision for income taxes
           
Results of Oil and Gas Producing Operations
  $ 51,764       421,755  
 
Proved Developed and Undeveloped Reserves

Our proved oil reserves have been estimated by petroleum reserve engineers in Dubai as of December 31, 2008, whom were affiliated with the Company through a mutual director until May 2008. Proved reserves are the estimated quantities that geologic and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are the quantities expected to be recovered through existing wells with existing equipment and operating methods. Due to the inherent uncertainties and the limited nature of reservoir data, such estimates are subject to change as additional information becomes available. The reserves actually recovered and the timing of production of
 
 
48
 

 

 
these reserves may be substantially different from the original estimate. Revisions result primarily from new information obtained from development drilling and production history, and changes in economic factors.

There were no proved undeveloped reserves as of December 31, 2010. Our proved developed reserves are summarized in the table below.
 
   
Crude Oil
Bbls
 
Reserves as of December 31:
 
2010
 
2009
 
Beginning of the period-Mubarek Field
   
 
30,301
 
Revisions of previous estimates
   
 
(6,582
Extensions and discoveries
   
 
 
Production
   
 
(23,719
)
End of the period
   
 
 

As of December 31, 2010, pursuant to the Participation Agreement, the Company is not liable for estimated well abandonment costs or net of salvage for the Mubarek field. Therefore, no abandonment costs are considered as part of the calculation of the full cost pool at December 31, 2010.

Price and cost revisions are primarily the net result of changes in year-end prices, based on beginning of year reserve estimates. Quantity estimate revisions are primarily the result of the extended economic life of proved reserves and proved undeveloped reserve additions attributable to increased development activity. The standardized measure of the Company’s proved crude oil and natural gas reserves at December 31, 2010 and 2009 is not provided as the wells were impaired to zero

No income taxes have been provided above as future net cash flows are expected to be less than the Company’s tax basis in the properties. Future operating costs for 2009 include a 14.5% royalty expense.

Changes in the Standardized Measure

The principle sources of change in the standardized measure of discounted future net cash flows for the years ended December 31, 2010 and 2009 were as follows:

   
2010
   
2009
 
Balance - beginning of year
  $     $ 1,062,572  
Sales, net of operating expenses
           
Extensions and discoveries
           
Accretion of discount
           
Net changes in prices and productions costs
           
Revisions of prior estimates
          (1,062,572 )
Balance - end of year
  $     $ -  

No income taxes have been provided above because none are expected to be due because the future net cash flows are expected to be less than the Company’s basis in the properties.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.
 
ITEM 9A. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

At the end of the period covered by this Annual Report an evaluation was carried out under the supervision of and with the participation of the Company’s management, including the Chief Executive Officer (“CEO”) and interim Chief Financial Officer (“CFO”), of the effectiveness of the design and operations of the Company’s disclosure controls and procedures (as defined in Rule 13a - 15(e) and Rule 15d - 15(e) under the Exchange Act). Based on that evaluation the CEO and CFO have concluded that the
 
49


 
Company’s disclosure controls and procedures are adequately designed and effective in ensuring that: (i) information required to be disclosed by the Company in reports that it files or submits to the SEC under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in applicable rules and forms and (ii) material information required to be disclosed in our reports filed under the Exchange Act is accumulated and communicated to our management, including our CEO and CFO, as appropriate, to allow for accurate and timely decisions regarding required disclosure.

Management’s Report on Internal Control over Financial Reporting

The Company’s management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act. Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation and fair presentation of financial statements for external purposes in accordance with generally accepted accounting principles.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Projections of any evaluation of effectiveness in future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management conducted an evaluation of the design and operation of the Company’s internal control over financial reporting as of December 31, 2010 based on the criteria set forth in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. This evaluation included review of the documentation of controls, evaluation of the design effectiveness of controls, testing of the operating effectiveness of controls and a conclusion on this evaluation. Based on this evaluation, management has concluded that the Company’s internal control over financial reporting was effective as of December 31, 2010.

This annual report does not include an attestation report of the Company’s independent registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by the Company’s independent registered public accounting firm pursuant to Section 404(c) of the Sarbanes-Oxley Act, which was added to the Sarbanes-Oxley Act by Section 989G of the recently enacted Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010.  Section 404(c) of the Sarbanes-Oxley Act exempts issuers that are neither accelerated filers nor large accelerated filers from the auditor attestation requirements of Section 404(b) of the Sarbanes-Oxley Act.  Accordingly the Company, as a smaller reporting company, is only required to provide management’s report on internal control over financial reporting in this annual report.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting identified in connection with the above-referenced evaluation by management of the effectiveness of our internal control over financial reporting that occurred during the fourth quarter ended December 31, 2010, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
 
ITEM 9B. OTHER INFORMATION
 
None.
 
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PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE

The Company’s Board of Directors consists currently of five directors. Directors are elected for one-year terms and serve until their successors are elected and qualified. All of the executive officers of the Company are full-time employees of the Company. Executive officers of the Company are appointed for a one-year term and serve until their respective successors have been selected and qualified; provided, however, such officers are subject to removal at any time by the affirmative vote of a majority of the Board of Directors. The ages of the directors, executive officers and key employees are shown as of December 31, 2010.

Name
 
Position
 
Director/Officer
Since
 
Age
Karim Jobanputra(1)
 
Chief Executive Officer, Director and Interim Principal Executive Officer
 
November 2, 2005
 
47
             
Michael D. Noonan(2)
 
Interim Chief Financial Officer, Vice President, Corporate, Secretary and Director
 
August 25, 2005
 
52
             
Shafiq Ur Rahman
 
Manager of Finance and Administration
 
May 29, 2006
 
59
             
Robert Curt(3)
 
Director
 
July 31, 2009
 
60
             
Oliver J Whittle(4)
 
Director
 
October 1, 2010
 
64
             
His Excellency Sheikh Jabor Bin Yusef Bin Jassim Al-Thani(5)
 
Director
 
October 6, 2010
 
46
 
(1)
Mr. Jobanputra was appointed Chief Executive Officer on September 12, 2007.
(2)
Mr. Noonan was appointed as director on November 16, 2005. Mr. Noonan was appointed Secretary effective May 30, 2006. Mr. Noonan was appointed interim Chief Financial Officer on August 11, 2008.
(3)
Mr. Curt was appointed as director on July 31, 2009 pursuant to its powers under the Company’s bylaws to fill vacant seats on the Board.
(4)
Mr. Whittle was appointed as director on October 1, 2010, pursuant to its powers under the Company’s bylaws to fill vacant seats on the Board.
(5)
H.E. Sheikh Jabor was appointed as director on October 6, 2010 pursuant to its powers under the Company’s bylaws to fill vacant seats on the Board.
 
The following is a description of the principal occupations and other employment during the past five years and their directorships in certain companies of the directors of the Company. This information is as reported by the respective directors.

Karim Jobanputra - Chief Executive Officer and Director. Karim Jobanputra, age 47, is an entrepreneur and owns companies that do business mostly in the Middle East and Europe. Mr. Jobanputra has experience in the areas of corporate finance and international business development.  Mr. Jobanputra is an entrepreneur and dedicates less than 100% of his business efforts to the business of Sky.  Mr. Jobanputra has other business interests, some of which may be in the oil and gas industry, and serves on the board of directors and as an officer for private companies.  Mr. Jobanputra also works as a self-employed consultant based in the United Kingdom and has provided consulting services to companies in the areas of corporate finance and business development in the Asian and Middle East markets, including Indonesia, Qatar, Saudi Arabia, India and China.

Michael D. Noonan - Interim Chief Financial Officer, Vice President, Corporate and Director. Michael D. Noonan, age 52, has been the Company’s Vice President, Corporate since August 25, 2005 and was appointed interim Chief Financial Officer on August 11, 2008. Mr. Noonan has more than 20 years of corporate finance, corporate governance and investor relations experience. Prior to joining the Company, Mr. Noonan worked for Forgent Networks from May 2002 to February 2006, where he most recently served as the Senior Director of Investor Relations.  Prior to working at Forgent, Mr. Noonan was employed for two years from March 2000 to March 2002, by Pierpont Communications, an investor and public relations firm, where he was a Senior Vice President. Mr. Noonan has also served as director of investor relations and corporate communications at Integrated Electrical Services, an electrical services company, and manager of investor relations and public affairs for Sterling Chemicals, a manufacturer of commodity chemicals. He received a Bachelor of Business Administration degree in Business Administration and Economics from Simon Fraser University in British Columbia, Canada; a Master of Business Administration degree from Athabasca University in Alberta, Canada; and an Executive Juris Doctorate from Concord School of Law in Los Angeles, California.
  
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Shafiq Ur Rahman - Manager of Finance and Administration. Shafiq Ur Rahman, age 59, is our Manager of Finance and Administration. Mr. Rahman has more than 30 years experience in the oil and gas industry. Prior to joining the Company he served as Chief Accountant and Director of Finance and Administration for several companies, including in the past, Huston Oil and Minerals, Tenneco Oil, Lundin Oil (formerly International Petroleum Inc.), Arabex Petroleum, and Coplex Resources. From 1993-2003 Mr. Rahman worked as Chief Accountant to Resource Petrochemical Consultants. From October 2003- December 2005, Mr. Rahman was employed by Tanganyika Oil Company as Chief Accountant for its subsidiary Dublin International Petroleum (Syria). Mr. Rahman took an extended vacation prior to joining us on a part-time basis in February and full-time beginning in May of 2006. Mr. Rahman’s global experience includes working in various countries in the Middle East, North and West Africa, and Asia. Mr. Rahman has a Bachelor in Commerce degree from Karachi University.
 
Robert Curt – Director. Robert P. Curt, age 60, is a Director and has over thirty years of experience, primarily as an executive in Marine Transportation and Supply related functions. He is currently a Director, Projects at Mallory, Jones, Lynch, Flynn and Assoc., an independent consultant to the marine industry. Mr. Curt retired from ExxonMobil in 2007 after assignments in a variety of positions up to and including General Manager Marine Transportation for ExxonMobil Refining & Supply Company and Managing Director, Qatar Gas Transport Company. He is also a Trustee of the US Merchant Marine Academy and a member of the American Bureau of Shipping’s Advisory Council and Nominating Committee and serves on the boards of two publicly traded shipping and ship building companies. Mr. Curt is a 1972 graduate of the U.S. Merchant Marine Academy and holds an MBA in Finance from Iona College.
 
Oliver J. Whittle – Director. Oliver Whittle, age 64, has over forty years of international banking experience, and was formerly the Chief Executive Officer of Raiffeisen Bank Albania, the largest bank in the country.  Raiffeisen Bank Albania has an asset base of approximately € 2 billion with a network of more than one hundred branches throughout the country. Mr. Whittle’s background includes over thirty years of service with Barclays Bank plc in a variety of senior positions including many aspects of its international operations.  Additionally, Mr. Whittle has had senior postings with several Eastern European financial institutions prior to his current assignment with Raiffeisen. Mr. Whittle is a graduate of London Guildhall University with a BA (Hons) in Financial Services, and has memberships with the Associate Chartered Institute of Bankers (ACIB) and the Chartered Institute of Personnel and Development (MIPD).

His Excellency Sheikh Jabor Bin Yusef Bin Jassim Al-Thani (“H.E. Sheikh Jabor”) – Director. H.E. Sheikh Jabor, age 46, is the chairman and director of several privately established companies in Qatar, which are active in industrial, commercial, representation, real-estate, energy, conference and exhibition industries. H.E. Sheikh Jabor chairs the Energy and Environmental Holding, and United Group for Projects, whose subsidiary Qatar Expo hosted the Forbes CEO Middle East Forum.

H.E Sheikh Jabor is the Chairman of insurance and reinsurance that includes two regulated entities by Qatar Financial Center Regulatory Authority (QFCRA). He also serves on the advisory board of directors of Georgetown University in Qatar.

Relationships between Directors and Officers

None of our executive officers or directors or key employees is related by blood, marriage or adoption to any other director or executive officer.

Arrangements between Directors and Officers

To our knowledge, there is no arrangement or understanding between any of our officers and any other person pursuant to which the officer was selected to serve as an officer.

Legal Proceedings, Cease Trade Orders and Bankruptcy

As of the date of this Annual Report, no director or executive officer of the Company and no shareholder holding more than 5% of any class of voting securities in the Company, or any associate of any such director, officer or shareholder is a party adverse to the Company or any of our subsidiaries or has an interest adverse to the Company or any of our subsidiaries.

No director or executive officer of the Company is, as at the date of this Annual Report, or was within 10 years before the date of this Annual Report, a director, chief executive officer or chief financial officer of any company (including the Company), that:
 
 
(a)
was subject to a cease trade order, an order similar to a cease trade order or an order that denied the relevant company access to any exemption under securities legislation, for a period of more than 30 consecutive days, that was issued while the director or executive officer was acting in the capacity as director, chief executive officer or chief financial officer; or

 
(b)
was subject to a cease trade order, an order similar to a cease trade order or an order that denied the relevant company access to any exemption under securities legislation, for a period of more than 30 consecutive days, that was issued after the director or executive officer ceased to be a director, chief executive officer or chief financial officer and which resulted from an event that occurred while that person was acting in the capacity as director, chief executive officer or chief financial officer.
 
 
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No director or executive officer of the Company, and no shareholder holding a sufficient number of securities of the Company to affect materially the control of the Company:
 
 
(a)
is, as at the date of this Annual Report, or has been within the 10 years before the date of this Annual Report, a director or executive officer of any company (including the Company) that, while that person was acting in that capacity, or within a year of that person ceasing to act in that capacity, became bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency or was subject to or instituted any proceedings, arrangement or compromise with creditors or had a receiver, receiver manager or trustee appointed to hold its assets;

 
(b)
has, within 10 years before the date of this Annual Report, become bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency, or become subject to or instituted any proceedings, arrangement or compromise with creditors, or had a receiver, receiver manager or trustee appointed to hold the assets of the director, executive officer or shareholder;

 
(c)
has, within 10 years before the date of this Annual Report, been the subject of, or a party to, any U.S. federal or state judicial or administrative order, judgment, decree, or finding, not subsequently reversed, suspended or vacated, relating to an alleged violation of: (i) any U.S. federal or state securities or commodities law or regulation; or (ii) any law or regulation respecting financial institutions or insurance companies including, but not limited to, a temporary or permanent injunction, order of disgorgement or restitution, civil money penalty or temporary or permanent cease-and-desist order, or removal or prohibition order; or (iii) any law or regulation prohibiting mail or wire fraud or fraud in connection with any business entity; or

 
(d)
has, within 10 years before the date of this Annual Report, been the subject of, or a party to, any sanction or order, not subsequently reversed, suspended or vacated, of any self-regulatory organization (as defined in Section 3(a)(26) of the Exchange Act (15 U.S.C.78c(a)(26))), any registered entity (as defined in Section 1(a)(29) of the Commodity Exchange Act (7 U.S.C.1(a)(29))), or any equivalent exchange, association, entity or organization that has disciplinary authority over its members or persons associated with a member.

No director or executive officer of the Company, and no shareholder holding a sufficient number of securities of the Company to affect materially the control of the Company has been subject to:
 
 
(a)
any penalties or sanctions imposed by a court relating to securities legislation or by a securities regulatory authority or has entered into a settlement agreement with a securities regulatory authority; or

 
(b)
any other penalties or sanctions imposed by a court or regulatory body that would likely be considered important to a reasonable investor in making an investment decision.

Corporate Governance

The Company’s Board of Directors is responsible for the Company’s Corporate Governance policies and has separately designated standing Compensation, Nominating, and Audit Committees. During 2010, the full Board handled the responsibilities of the designated committees until such time as qualified independent directors could be nominated and appointed to the Board and assigned to the committees. The Company’s Board determines independence based on the criteria for independence and un-relatedness prescribed by the Sarbanes-Oxley Act of 2002, section 10A (m) (3) of the Exchange and section 803A of the NYSE Amex Company Guide.

Compensation Committee

Compensation of the Company’s Chief Executive Officer and all other officers is recommended to the Board for determination by the Compensation Committee. The Compensation Committee develops reviews and monitors director and executive compensation and policies. The Compensation Committee is also responsible for annually reviewing the adequacy of compensation for directors and others and the composition of compensation packages. The Company’s Chief Executive Officer cannot be present during the Committee’s deliberations or vote.

During 2010, the Compensation Committee had no members.  Accordingly, the members of the Company’s Board of Directors, as a whole, performed the functions and responsibilities of the Compensation Committee.
 
53
 

 

Nominating Committee

Nominees for the election to the Board of Directors are recommended by the Nominating Committee. The Company has adopted a formal written Board resolution addressing the nomination process and such related matters as may be required under federal securities laws. During 2010, the Corporate Governance and Nominating Committee had no members.  Accordingly, the members of the Company’s Board of Directors, as a whole, performed the functions and responsibilities of the Nominating Committee.

There have been no material changes to the procedures by which security holders may recommend nominees to the Company’s Board of Directors.

Audit Committee

The Company’s Audit Committee Charter designated an Audit Committee established in accordance with section 3(a)(58)(A) of the Exchange Act.

During 2010, the Company’s Audit Committee had no members.  Accordingly, the members of the Company’s Board of Directors, as a whole, performed the functions and responsibilities of the Audit Committee.

Diversity of the Board

The Company does not have a formal policy regarding diversity in the selection of nominees for directors. The Board does however consider diversity as part of its overall selection strategy. In considering diversity of the Board as a criteria for selecting nominees, the Corporate Board takes into account various factors and perspectives, including differences of viewpoint, professional experience, education, skills and other individual qualities and attributes that contribute to Board heterogeneity, as well as race, gender and national origin. The Board seeks persons with leadership experience in a variety of contexts and, among public company leaders, across a variety of industries. The Board believes that this expansive conceptualization of diversity is the most effective means to implement Board diversity. The Board will assess the effectiveness of this approach as part of its annual assessment of the performance of the Board.

Board Leadership Structure

The Board has reviewed the Company’s current Board leadership structure — which consists of a Chief Executive Officer and no Chairman of the Board— in light of the composition of the Board, the company’s size, the nature of the company’s business, the regulatory framework under which the company operates, the company’s shareholder base, the Company’s peer group and other
relevant factors, and has determined that this structure is currently the most appropriate Board leadership structure for our company.
The Company does not have a lead independent director. Given the size of the Board, the Board does not believe that selecting a lead independent director would add significant benefits to the Board oversight role.

The Role of the Board in Risk Oversight

The understanding, identification and management of risk are essential elements for the successful management of the Company. Risk oversight begins with the Board of Directors. The Board reviews and discusses policies with respect to risk assessment and risk management. The Board also has oversight responsibility with respect to the integrity of the Company’s financial reporting process and systems of internal control regarding finance and accounting, as well as its financial statements.

At the management level, an internal audit provides reliable and timely information to the Board and management regarding the Company’s effectiveness in identifying and appropriately controlling risks. Annually, management presents to the Board a report summarizing the review of the Company’s methods for identifying and managing risks. The Company also has a comprehensive internal risk framework, which facilitates performance of risk oversight by the Board.

Code of Ethics

We have adopted a corporate code of ethics administered by our corporate secretary, Michael D. Noonan. We believe our code of ethics is reasonably designed to deter wrongdoing and promote honest and ethical conduct, to provide full, fair, accurate, timely and understandable disclosure in public reports, to comply with applicable laws, to ensure prompt internal reporting of code violations, and to provide accountability for adherence to the code. Our code of ethics provides written standards that are reasonably designed to deter wrongdoing and to promote:

 
 
Honest and ethical conduct, including the ethical handling of actual or apparent conflicts of interest between personal and professional relationships;
 
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Full, fair, accurate, timely and understandable disclosure in reports and documents that are filed with, or submitted to, the Commission and in other public communications made by an issuer;

 
Compliance with applicable governmental laws, rules and regulations;

 
The prompt internal reporting of violations of the code to an appropriate person or persons identified in the code; and

 
Accountability for adherence to the code.

Our Code of Ethics is available at our website at www.skypetroleum.com. We intend to disclose any waiver from a provision of our code of ethics that applies to any of our principal executive officer, principal financial officer, principal accounting officer or controller or persons performing similar functions that relates to any element of