UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 20-F

	o	REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) OR (g) OF THE SECURITIES EXCHANGE ACT OF 1934
OR
	x	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the fiscal year ended December 31, 2013
OR
	o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
OR
	o	SHELL COMPANY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Date of event requiring this shell company report: _____________

For the transition period from ________ to ________

Commission file number 005-86157

Arabella Exploration, Inc.

(Exact name of the Registrant as specified in its charter)

Cayman Islands

(Jurisdiction of incorporation or organization)

500 W. Texas Avenue

Suite 1450

Midland, Texas 79701

(Address of principal executive offices)

Jason Hoisager

(432) 897-4755

jason.hoisager@arabellaexploration.com

500 W. Texas Avenue

Suite 1450

Midland, Texas 79701

(Name, Telephone, E-mail and/or Facsimile Number and Address of Company Contact Person)

Securities registered or to be registered pursuant to Section 12(b) of the Act: None.

Securities registered or to be registered pursuant to Section 12(g) of the Act:

Units

(Title of Class)

Ordinary Shares, $0.001 par value

(Title of Class)

Ordinary Share Purchase Warrants

(Title of Class)

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act: None.

On April 30, 2014, the issuer had 4,829,826 shares outstanding.

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

If this report is an annual or transition report, indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934.Yes o  No x

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.

o Large Accelerated filer o Accelerated filer  x Non-accelerated filer

Indicate by check mark which basis of accounting the registrant has used to prepare the financial statements included in this filing:

x US GAAP o International Financial Reporting Standards as issued by the International Accounting Standards Board o Other

If “Other” has been checked in response to the previous question, indicate by check mark which financial statement item the registrant has elected to
follow.    o Item 17    o Item 18

If this is an annual report, indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No x

Table of Contents

			Page
PART I			3
ITEM 1. IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS			3
ITEM 2. OFFER STATISTICS AND EXPECTED TIMETABLE			3
ITEM 3. KEY INFORMATION			3
	A.	Selected financial data	3
	B.	Capitalization and Indebtedness	3
	C.	Reasons for the Offer and Use of Proceeds	3
	D.	Risk factors	3
ITEM 4. INFORMATION ON THE COMPANY			11
	A.	History and Development of the Company	11
	B.	Business Overview	13
	C.	Organizational Structure	33
	D.	Property, Plant and Equipment	33
ITEM 4A. UNRESOLVED STAFF COMMENTS			33
ITEM 5. OPERATING AND FINANCIAL REVIEW AND PROSPECTS			33
ITEM 6. DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES			39
	A.	Directors and senior management	39
	B.	Compensation	41
	C.	Board Practices	42
	Board Committees		42
	Director Independence		42
	D.	Employees	42
	E.	Share Ownership	43
ITEM 7. MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS			43
	A.	Major shareholders	43
	B.	Related Party Transactions	44
	C.	Interests of Experts and Counsel	45

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Table of Contents

			Page
ITEM 8. FINANCIAL INFORMATION			45
	A.	Financial Statements and Other Financial Information	45
	B.	Significant Changes	45
ITEM 9. THE OFFER AND LISTING			46
	A.	Offer and Listing Details	46
	B.	Plan of Distribution	46
	C.	Markets	46
	D.	Selling Shareholders	46
	E.	Dilution	46
	F.	Expenses of the Issue	46
ITEM 10. ADDITIONAL INFORMATION			47
	A.	Share Capital	47
	B.	Memorandum and Articles of Association	47
	C.	Material Contracts	47
	D.	Exchange controls	48
	E.	Taxation	48
	F.	Dividends and paying agents	54
	G.	Statement by experts	54
	H.	Documents on display	54
	I.	Subsidiary Information	55
ITEM 11. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK			55
ITEM 12. DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES			55
PART II			56
ITEM 13. DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES			56
ITEM 14. MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS			56
	A.	Use of Proceeds	56
ITEM 15. CONTROLS AND PROCEDURES			56

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Table of Contents

	Page
ITEM 16. [RESERVED]	57
ITEM 16A. AUDIT COMMITTEE FINANCIAL EXPERT	57
The audit committee currently consists of William B. Heyn.  Additional members are expected to be appointed in the near future	57
ITEM 16B. CODE OF ETHICS	57
ITEM 16C. PRINCIPAL ACCOUNTANT FEES AND SERVICES	57
ITEM 16D. EXEMPTIONS FROM THE LISTING STANDARDS FOR AUDIT COMMITTEES	57
ITEM 16E. PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PURCHASERS	57
ITEM 16F. CHANGES IN REGISTRANT’S CERTIFYING ACCOUNTANT.	57
ITEM 16G. CORPORATE GOVERNANCE	57
PART III	58
ITEM 17. FINANCIAL STATEMENTS	58
ITEM 18. FINANCIAL STATEMENTS	58
ITEM 19. EXHIBITS	58

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CERTAIN INFORMATION

Except where the context requires otherwise and for purposes of this report only:

· “Arabella,” “we,” “us,” “Company,” or “our,” refers to Arabella Exploration, Inc. (formerly known as Lone Oak Acquisition Corporation), a company with limited liability incorporated in the Cayman Islands.

· “Arabella LLC” refers to Arabella Exploration, Limited Liability Company, which is our wholly owned subsidiary as of December 24, 2013, the closing date of the Business Combination.

· “Business Combination” or “Acquisition” refers to our acquisition of Arabella LLC on December 24, 2013, pursuant to the reverse merger of our wholly owned subsidiary, Arabella Exploration Corp., with and into Arabella LLC.

· “IPO” or “initial public offering” refers to our initial public offering pursuant to our prospectus, dated March 16, 2011 and filed with the Securities and Exchange Commission on March 22, 2011, which was consummated on March 30, 2011.

· “ordinary shares” refers to our ordinary shares, par value $0.001 per share.

· references to “founding shareholders” refer collectively to Berke Bakay, BBS Capital Fund, LP, Hauser Holdings LLC, William B. Heyn, James R. Preissler, John V. Calce, Baris Merzeci and Can Aydinoglu, each of whom purchased Arabella shares and warrants prior to our initial public offering;

· references to “public shareholders” refer to the holders of shares purchased in Arabella’s initial public offering; and

· Any discrepancies in any table between the amounts identified as total amounts and the sum of the amounts listed therein are due to rounding.

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FORWARD-LOOKING STATEMENTS

The statements contained in this report that are not purely historical are forward-looking statements. Our forward-looking statements include, but are not limited to, statements regarding our or our management’s expectations, hopes, beliefs, intentions or strategies regarding the future. In addition, any statements that refer to projections, forecasts or other characterizations of future events or circumstances, including any underlying assumptions, are forward-looking statements. The words “anticipates,” “believe,” “continue,” “could,” “estimate,” “expect,” “intend,” “may,” “might,” “plan,” “possible,” “potential,” “predict,” “project,” “should,” “would” and similar expressions may identify forward-looking statements, but the absence of these words does not mean that a statement is not forward-looking. Forward-looking statements in this report may include, for example, statements about our:

· Continued compliance with government regulations;

· Changing legislation or regulatory environments;

· Requirements or changes affecting the businesses in which we are engaged;

· Planned capital expenditures and availability of capital resources to fund those expenditures;

· Industry trends, including factors affecting supply and demand;

· Labor and personnel relations;

· Credit risks affecting our revenue, growth and profitability;

· Estimates of our proved oil and gas reserves;

· Changes in the oil and gas industry in general and oil and gas prices specifically;

· Estimates of future oil and gas production;

· Ability of our management to effectively manage our growth, including implementing effective controls and procedures and attracting and retaining key management and personnel;

· Access to capital;

· Changing interpretations of generally accepted accounting principles;

· Our public securities’ limited liquidity and trading;

· General economic conditions; and

· Other relevant risks detailed in our filings with the Securities and Exchange Commission.

The forward-looking statements contained in this report are based on our current expectations and beliefs concerning future developments and their potential effects on us. There can be no assurance that future developments affecting us will be those that we have anticipated. These forward-looking statements involve a number of risks, uncertainties (some of which are beyond our control) or other assumptions that may cause actual results or performance to be materially different from those expressed or implied by these forward-looking statements. These risks and uncertainties include, but are not limited to, those factors described under the heading “Risk Factors.” Should one or more of these risks or uncertainties materialize, or should any of our assumptions prove incorrect, actual results may vary in material respects from those projected in these forward-looking statements. We undertake no obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required under applicable securities laws and/or if and when management knows or has a reasonable basis on which to conclude that previously disclosed projections are no longer reasonably attainable.

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PART I

ITEM 1. IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS

Not required.

ITEM 2. OFFER STATISTICS AND EXPECTED TIMETABLE

Not required.

ITEM 3. KEY INFORMATION

A. Selected financial data

Following the Business Combination, Arabella LLC is considered to be our predecessor for accounting purposes, as further described in Item 18 of this report. The following selected consolidated financial data have been derived from our consolidated financial statements as of December 31, 2013 and 2012 and for the years ended December 31, 2013, 2012 and 2011, which are included elsewhere in this report. The consolidated financial statements are prepared and presented in accordance with US GAAP. The results of operations in any period may not necessarily be indicative of the results that may be expected for any future period. See “Risk Factors” included elsewhere in this report. The selected combined financial information as of December 31, 2013, 2012 and 2011 should be read in conjunction with those consolidated financial statements and the accompanying notes and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included elsewhere in this report.

	As of December 31,			As of December 31,			As of December 31,
Balance Sheet Data	2013			2012			2011
Working capital deficit	$	(1,240,656	)	$	(41,660	)	$	(6,270	)
Total assets		15,852,807			1,756,309			197,293
Total liabilities		6,847,437			1,307,897			168,757
Shareholders’ equity		9,005,370			448,412			28,536

Selected statement of operation data:	For the year ended December 31, 2013		For the year ended December 31, 2012		For the year ended December 31, 2011
Total Revenues	$	1,421,915	$	468,782	$	51,010
Total costs and operating expenses		1,230,196		147,466		52,475
Net income (loss)		191,719		321,316		(1,465	)

B. Capitalization and Indebtedness

Not required.

C. Reasons for the Offer and Use of Proceeds

Not required.

D. Risk factors

An investment in our securities involves a high degree of risk.  You should consider carefully all of the risks described below, together with the other information contained in this annual report before making a decision to invest in our securities.  If any of the following events occur, our business, financial condition and operating results may be materially adversely affected. In that event, the trading price of our securities could decline and you could lose all or part of your investment.

Risks Related to our Business

We may not be able to continue as a going concern without additional financing. If such financing is not available to us or is not available to us on acceptable terms, we may be forced to cease operations.

We have recurring working capital deficits and are dependent on outside sources of financing for continuation of our operations. The report of our independent registered public accounting firm relating to our financial statements for the year ended December 31, 2013 includes an explanatory paragraph stating that these factors, among others, raise substantial doubt about our ability to continue as a going concern. If we are not able to raise additional funds, or are unable to raise funds on acceptable terms, we may be forced to curtail or cease operations.

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A substantial or extended decline in oil and natural gas prices may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.

The price we receive for our oil and natural gas production heavily influence our revenue, profitability, access to capital and future rate of growth. Oil and natural gas are commodities and, therefore, 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. These markets may be volatile in the future. The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control. These factors include, but are not limited to, the following:

· changes in global supply and demand for oil and natural gas;

· the actions of the Organization of Petroleum Exporting Countries, or OPEC;

· the price and quantity of imports of foreign oil and natural gas;

· political conditions, including embargoes, in or affecting other oil-producing activity;

· the level of global oil and natural gas exploration and production activity;

· the level of global oil and natural gas inventories;

· weather conditions;

· technological advances affecting energy consumption; and

· the price and availability of alternative fuels.

Lower oil and natural gas prices may not only decrease our revenues on a per unit basis but also may reduce the amount of oil and natural gas that we can produce economically. Lower prices will also negatively impact the value of our proved reserves. A substantial or extended decline in oil or natural gas prices may materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures.

A substantial percentage of our proven properties are undeveloped; therefore the risk associated with our success is greater than would be the case if the majority of our properties were categorized as proved developed producing.

Because a substantial percentage of our proven properties are proved undeveloped (approximately 93%) we will require significant additional capital to develop such properties before they may become productive. Please see the section entitled “Oil and Gas Production Prices and Production Costs” below. Further, because of the inherent uncertainties associated with drilling for oil and gas, some of these properties may never be developed to the extent that they result in positive cash flow. Even if we are successful in our development efforts, it could take several years for a significant portion of our undeveloped properties to be developed and to positive cash flow.

In order to fund our development costs, we may be forced to seek alternative sources for cash, through the issuance of additional equity or debt securities, increased borrowings or other means.

Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations.

Our future success will depend on the success of our exploitation, exploration, development and production activities. Our oil and natural gas exploration and production activities are subject to numerous risks beyond our control; including the risk that drilling will not result in commercially viable oil or natural gas production. Our decisions to purchase, explore, develop or otherwise exploit prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. Please read “—Reserve estimates depend on many assumptions that may turn out to be inaccurate” (below) for a discussion of the uncertainty involved in these processes. Our cost of drilling, completing and operating wells is often uncertain before drilling commences. Overruns in budgeted expenditures are common risks that can make a particular project uneconomical. 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;

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· shortages of or delays in obtaining equipment and qualified personnel;

· equipment failures or accidents;

· adverse weather conditions;

· reductions in oil and natural gas prices;

· title problems; and

· limitations in the market for oil and natural gas.

If our assessments of recently purchased properties are materially inaccurate, it could have significant impact on future operations and earnings.

We have aggressively expanded our base of producing properties. The successful acquisition of properties requires assessments of many factors, which are inherently inexact and may be inaccurate, including the following:

· the amount of recoverable reserves;

· future oil and natural gas prices;

· estimates of operating costs;

· estimates of future development costs;

· estimates of the costs and timing of plugging and abandonment; and

· potential environmental and other liabilities.

Our assessment will not reveal all existing or potential problems, nor will it permit us to become familiar enough with the properties to assess fully their capabilities and deficiencies. As noted previously, we plan to undertake further development of our properties through the use of cash flow from existing production. Therefore, a material deviation in our assessments of these factors could result in less cash flow being available for such purposes than we presently anticipate, which could either delay future development operations (and delay the anticipated conversion of reserves into cash), or cause us to seek alternative sources to finance development activities.

Decreases in oil and natural gas prices may require us to take write-downs of the carrying values of our oil and natural gas properties, potentially requiring earlier than anticipated debt repayment and negatively impacting the trading value of our securities.

Accounting rules require that we review periodically the carrying value of our oil and natural gas properties for possible impairment. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our oil and natural gas properties. In the future, our properties may serve as collateral for advances under our prospective credit facilities, a write-down in the carrying values of our properties could require us to repay debt earlier than we would otherwise be required. A write-down could also constitute a non-cash charge to earnings. It is likely the cumulative effect of a write-down could also negatively impact the trading price of our securities.

We sell our natural gas to a limited number of buyers, and if one of our buyers was unable to pay us for our natural gas products, our financial results could be adversely affected.

We sell the majority of our natural gas to a small number of natural gas purchasing companies. There is often consolidation in this market and it is possible that we might be faced with a significant concentration of our natural gas buyers. In the event that one of our natural gas buyers was unable to make payment to us for its purchases of natural gas, our financial results could be adversely affected

We sell our oil to many different buyers and believe that we have many primary and secondary buyers to choose from.

Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to economic factors. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of our reported reserves.

5

In order to prepare our estimates, we must project production rates and timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. The process also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Therefore, estimates of oil and natural gas reserves may be inherently imprecise.

Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves most likely will vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of our reported reserves. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control.

You should not assume that the present value of future net revenues from our reported proved reserves is the current market value of our estimated oil and natural gas reserves. In accordance with SEC requirements, we base the estimated discounted future net cash flows from our proved reserves on the average price during the 12-month period prior to the ending date of the period covered by the report. Actual future prices and costs may differ materially from those used in the present value estimate. If future values decline or costs increase it could negatively impact our ability to finance operations, and individual properties could cease being commercially viable, affecting our decision to continue operations on producing properties or to attempt to develop properties. All of these factors would have a negative impact on earnings and net income, and most likely the trading price of our securities. These factors could also result in the acceleration of debt repayment and a reduction in our borrowing base under any prospective credit facilities.

We have limited experience drilling and operating wells and this experience may lead to variances, positive or negative, in our operations.

We have a limited history of operating wells. This lack of experience could result in errors in the methods we use for drilling and maintaining our wells, which could result in poorer than expected operating results. In addition, the lack of experience operating wells could result in inefficiencies in its operations that result in greater expenditures than are required under the circumstances.

Prospects that we decide to drill may not yield oil or natural gas in commercially viable quantities.

Our prospects are in various stages of evaluation, ranging from prospects that are currently being drilled, to prospects that will require substantial additional seismic data processing and interpretation. There is no way to predict in advance of drilling and testing whether any particular prospect will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. This risk may be enhanced in our situation, due to the fact that a significant percentage (93%) of our proved reserves is currently proved undeveloped reserves. The use of seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercial quantities. We cannot assure you that the analogies we draw from available data from other wells, more fully explored prospects or producing fields will be applicable to our drilling prospects.

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

We are not insured against all risks. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition or results of operations. Our oil and natural gas exploration and production activities are 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 and shoreline contamination;

· abnormally pressured formations;

· mechanical difficulties such as stuck oil field drilling and service tools and casing collapse;

· fires and explosions;

· personal injuries and death; and

· natural disasters.

Any of these risks could adversely affect our ability to conduct operations or result in substantial losses to us. We may elect not to obtain insurance if we believe that 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 occurs and is not fully covered by insurance, then it could adversely affect us.

6

We are subject to complex laws that can affect the cost, manner or feasibility of doing business.

Exploration, development, production and sale of oil and natural gas are subject to extensive federal, state, local and international regulation. We may be required to make large expenditures to comply with governmental regulations. Matters subject to regulation include:

· discharge permits for drilling operations;

· drilling bonds;

· reports concerning operations;

· the spacing of wells;

· unitization and pooling of properties; and

· taxation.

Under these laws, we could be liable for personal injuries, property damage and other damages. Failure to comply with these laws also may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Moreover, these laws could change in ways that substantially increase our costs. Any such liabilities, penalties, suspensions, terminations or regulatory changes could materially adversely affect our financial condition and results of operations.

Our operations may incur substantial liabilities to comply with the environmental laws and regulations.

Our oil and natural gas operations are subject to stringent federal, state and local laws and regulations relating to the release or disposal of materials into the environment or otherwise relating to environmental protection. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentration of substances that can be released into the environment in connection with drilling and production activities, limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas, and impose substantial liabilities for pollution resulting from our operations. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, incurrence of investigatory or remedial obligations or the imposition of injunctive relief. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly waste handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to maintain compliance, and may otherwise have a material adverse effect on our results of operations, competitive position or financial condition as well as the industry in general. Under these environmental laws and regulations, we could be held strictly liable for the removal or remediation of previously released materials or property contamination regardless of whether we were responsible for the release or if our operations were standard in the industry at the time they were performed.

If our indebtedness increases, it could reduce our financial flexibility.

As of December 31, 2013, we had no third party debt.  If in the future we raise funds through a debt facility, the level of our indebtedness could affect our operations in several ways, including the following:

· a significant portion of our cash flow could be used to service the indebtedness,

· a high level of debt would increase our vulnerability to general adverse economic and industry conditions,

· the covenants contained in a prospective credit facility may limit our ability to borrow additional funds, dispose of assets, pay dividends and make certain investments,

· a high level of debt could impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate or other purposes.

Unless we replace our oil and natural gas reserves, our reserves and production will decline, which would adversely affect our cash flows and income.

Unless we conduct successful development, exploitation and exploration activities or acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our future oil and natural gas reserves and production, and, therefore our cash flow and income, are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. If we are unable to develop, exploit, find or acquire additional reserves to replace our current and future production, our cash flow and income will decline as production declines, until our existing properties would be incapable of sustaining commercial production.

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If our access to markets is restricted, it could negatively impact our production, our income and ultimately our ability to retain our leases.

Market conditions or the unavailability of satisfactory oil and natural gas transportation arrangements may hinder our access to oil and natural gas markets or delay our production. The availability of a ready market for our oil and natural gas production depends 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. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines and processing facilities owned and operated by third parties. Our failure to obtain such services on acceptable terms could materially harm our business.

Currently, the majority of our production is sold to marketers and other purchasers that have access to nearby pipeline facilities. However, as Arabella begins to further develop our properties, we may find production in areas with limited or no access to pipelines or compression facilities. Such restrictions on our ability to sell our oil or natural gas have several adverse effects, including higher transportation costs, fewer potential purchasers (thereby potentially resulting in a lower selling price) or, in the event we were unable to market and sustain production from a particular lease for an extended time, possibly causing us to lose a lease due to lack of production.

Hedging transactions may limit our potential gains.

In order to reduce commodity price uncertainty and increase cash flow predictability relating to the marketing of our crude oil and natural gas, we may enter into crude oil and natural gas price hedging arrangements with respect to a portion of our expected production. While intended to reduce the effects of volatile crude oil and natural gas prices, such transactions may limit our potential gains if crude oil and natural gas prices rise over the price established by the arrangements.

All of our properties are located in the same major geographic area.

Because substantially all of the properties leased by us are located in the Delaware Basin in Texas, we face geographic concentration risk. If the properties leased by us prove to be unable to produce profitable oil and natural gas, it may force us to seek properties in other regions. This could require us to make significant expenditures or cease operations, and may otherwise have a material adverse effect on our results of operations, competitive position or financial condition.

Risks Related to Our Being a Foreign Private Issuer

As a foreign private issuer, we are exempt from certain rules that are applicable to U.S. public companies, and while we have agreed with the underwriters in our IPO to comply with certain of these requirements, such agreement can be waived without your consent and you may receive less information about us and our operations than you would receive if such agreements were not waived or we were a U.S. company.

As a foreign private issuer, we are exempt from the rules of the Exchange Act prescribing the furnishing and content of proxy statements to shareholders, and our executive officers, directors and principal shareholders are exempt from certain of the reporting and short-swing profit recovery provisions contained in Section 16 of the Exchange Act. In addition, we are not required under the Exchange Act to file periodic reports and financial statements with the SEC as frequently or as promptly as U.S. companies whose securities are registered under the Exchange Act. Therefore you may receive less information about us than you would receive if we were a U.S. company. We expect to not meet the requirements of a foreign private issuer as of the next measurement period, June 30, 2014, as a result of the Business Combination with Arabella LLC. We expect to begin filing as a U.S. company with our annual report for the year ending December 31, 2014 in 2015.

Because we are incorporated under the laws of the Cayman Islands, you may face difficulty protecting your interests, and your ability to protect your rights through the U.S. federal courts may be limited.

We are a company incorporated under the laws of the Cayman Islands, and certain of our assets may in the future be located outside the United States. As a result, it may be difficult for investors to effect service of process within the United States in a way that will permit a U.S. court to have jurisdiction over us.

We are incorporated as a Cayman Islands exempted company. A Cayman Islands exempted company:

· is a company that conducts its business outside the Cayman Islands;

· is exempted from certain requirements of the Cayman Companies Law, including the

· filing of an annual return of its shareholders with the Registrar of Companies;

· does not have to make its register of shareholders open to inspection; and

· may obtain an undertaking against the imposition of any future taxation.

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Our corporate affairs are governed by our Amended and Restated Articles of Association, the Companies Law of the Cayman Islands, as the same may be supplemented or amended from time to time, which we refer to herein as the Companies Law, and the common law of the Cayman Islands. The rights of shareholders to take action against the directors, actions by minority shareholders and the fiduciary responsibilities of our directors to us under Cayman Islands law are to a large extent governed by the common law of the Cayman Islands. The common law of the Cayman Islands is derived in part from comparatively limited judicial precedent in the Cayman Islands, as well as from English common law, the decisions of whose courts are of persuasive authority, but are not binding on a court in the Cayman Islands. The rights of our shareholders and the fiduciary responsibilities of our directors under Cayman Islands law are not as clearly established as they would be under statutes or judicial precedent in some jurisdictions in the United States. In particular, the Cayman Islands has a less developed body of securities laws as compared to the United States, and some states, such as Delaware, have more fully developed and judicially interpreted bodies of corporate law. In addition, Cayman Islands companies may not have standing to initiate a shareholder derivative action in a federal court of the United States.

The Cayman Islands courts are also unlikely:

· to recognize or enforce against us judgments of courts of the United States based on certain civil liability provisions of U.S. securities laws; and

· to impose liabilities against us, in original actions brought in the Cayman Islands, based on certain civil liability provisions of U.S. securities laws that are penal in nature.

There is no statutory recognition in the Cayman Islands of judgments obtained in the United States. We have been advised by Conyers Dill & Pearman, our counsel as to Cayman Islands law, that (i) they are unaware of any proceedings that have been brought in the Cayman Islands to enforce judgments of the courts in the United States or to impose liabilities based on the civil liability provisions of the securities laws of the United States or any state in the United States; (ii) a final and conclusive judgment in the federal or state courts of the United States under which a sum of money is payable, other than a sum payable in respect of taxes, fines, penalties or similar charges, may be subject to enforcement proceedings as a debt in the courts of the Cayman Islands under the common law doctrine of obligation; and (iii) because it is uncertain whether a Cayman Islands court would determine that a judgment of a United States court based on the civil liability provisions of the securities laws of the United States or any state in the United States is in the nature of a penalty, it is uncertain whether such a liability judgment would be enforceable in the Cayman Islands. The Grand Court of the Cayman Islands may stay proceedings if concurrent proceedings are being brought elsewhere.

There is a risk that we will be classified as a passive foreign investment company, or “PFIC,” which could result in adverse U.S. federal income tax consequences to U.S. holders of our securities.

In general, we will be treated as a PFIC for any taxable year in which either (1) at least 75% of our gross income (including our pro rata share of the gross income of our 25% or more-owned corporate subsidiaries) is passive income or (2) at least 50% of the average value (or, in certain cases, adjusted bases) of our assets (including our pro rata share of the assets of our 25% or more-owned corporate subsidiaries) produce, or are held for the production of, passive income. Passive income generally includes dividends, interest, rents, royalties, and gains from the disposition of passive assets. If we are determined to be a PFIC for any taxable year (or portion thereof) that is included in the holding period of a U.S. Holder (as defined in the section entitled “Taxation—United States Federal Income Taxation—General”) of its securities, the U.S. Holder may be subject to increased U.S. federal income tax liability upon a sale or other disposition of our securities or the receipt of certain excess distributions from us and may be subject to additional reporting requirements. Based on the composition (and estimated values and adjusted bases) of the assets and nature of the income of us and our subsidiaries during our 2013 taxable year, we believe that we may be a PFIC for such year. However, because we have not performed a definitive analysis as to our PFIC status for our 2013 taxable year, there can be no assurance in respect to our PFIC status for such year or any future taxable year. U.S. Holders of our securities are urged to consult their own tax advisors regarding the possible application of the PFIC rules. See the discussion in the section entitled “Taxation—United States Federal Income Taxation—U.S. Holders—Passive Foreign Investment Company Rules.”

Risks Related to Our Securities

Our outstanding warrants may adversely affect the market price of our ordinary shares.

We have outstanding warrants to purchase 10,706,500 ordinary shares. We also issued an option to purchase 400,000 units to the representative of the underwriters of our IPO which, if exercised, could result in the issuance of 400,000 ordinary shares and 400,000 warrants. The sale, or even the possibility of sale, of the shares underlying the warrants and option could have an adverse effect on the market price for our securities or on our ability to obtain future financing. If and to the extent these warrants and option are exercised, you may experience dilution to your holdings.

If our ordinary shares become subject to the SEC’s penny stock rules, broker-dealers may experience difficulty in completing customer transactions and trading activity in our securities may be adversely affected.

If at any time we have net tangible assets of $5,000,000 or less and our ordinary shares have a market price per share of less than $5.00, transactions in our ordinary shares may be subject to the “penny stock” rules promulgated under the Securities Exchange Act of 1934. Under these rules, broker-dealers who recommend such securities to persons other than institutional accredited investors must:

· make a special written suitability determination for the purchaser;

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· receive the purchaser’s written agreement to the transaction prior to sale;

· provide the purchaser with risk disclosure documents which identify certain risks associated with investing in “penny stocks” and which describe the market for these “penny stocks” as well as a purchaser’s legal remedies; and

· obtain a signed and dated acknowledgment from the purchaser demonstrating that the purchaser has actually received the required risk disclosure document before a transaction in a “penny stock” can be completed.

If our ordinary shares become subject to these rules, broker-dealers may find it difficult to effectuate customer transactions and trading activity in our securities may be adversely affected. As a result, the market price of our securities may be depressed, and you may find it more difficult to sell our securities.

We have no plans to pay dividends on our ordinary shares. Shareholders may not receive funds without selling their shares.

We do not anticipate paying any cash dividends on our ordinary shares in the foreseeable future. We currently intend to retain future earnings, if any, to finance the expansion of our business. Our future dividend policy is within the discretion of our board of directors and will depend upon various factors, including our business, financial condition, results of operations, capital requirements and investment opportunities.

Our board of directors can, without shareholder approval, cause preferred stock to be issued on terms that adversely affect ordinary shareholders.

Under our Amended and Restated Memorandum and Articles of Association, our board of directors is authorized to issue up to 5,000,000 shares of preferred stock, of which none are issued and outstanding as of the date of this annual report. Also, our board of directors, without shareholder approval, may determine the price, rights, preferences, privileges and restrictions, including voting rights, of those shares. If the board causes shares of preferred stock to be issued, the rights of the holders of ordinary shares could be adversely affected. The board’s ability to determine the terms of preferred stock and to cause its issuance, while providing desirable flexibility in connection with possible acquisitions and other corporate purposes, could have the effect of making it more difficult for a third party to acquire a majority of our outstanding voting stock. Preferred shares issued by the board of directors could include voting rights, or even super voting rights, which could shift the ability to control the company to the holders of the preferred stock. Preferred shares could also have conversion rights into ordinary shares at a discount to the market price of the ordinary shares which could negatively affect the market for our ordinary shares. In addition, preferred shares would have preference in the event of liquidation of the corporation, which means that the holders of preferred shares would be entitled to receive the net assets of the corporation distributed in liquidation before the ordinary shareholders receive any distribution of the liquidated assets. We have no current plans to issue any preferred shares.

An effective registration statement may not be in place when an investor desires to exercise warrants, thus precluding such investor from being able to exercise his, her or its warrants for cash.

Holders of our warrants will be able to exercise the warrants for cash only if we have an effective registration statement covering the ordinary shares issuable upon exercise of the warrants and a current prospectus relating to such ordinary shares and, even in the case of a cashless exercise which is permitted in certain circumstances, such ordinary shares are qualified for sale or exempt from qualification under the applicable securities laws of the states in which the various holders of warrants reside. Under the terms of the warrant agreement, we have agreed to use our best efforts to meet these conditions and to maintain a current prospectus relating to the ordinary shares issuable upon exercise of the warrants until the expiration of the warrants. However, we cannot assure you that we will be able to do so, and if we do not maintain a current prospectus related to the ordinary shares issuable upon exercise of the warrants, holders will only be able to exercise their warrants on a cashless basis.

An investor will only be able to exercise a warrant if the issuance of ordinary shares upon such exercise has been registered or qualified or is deemed exempt under the securities laws of the state of residence of the holder of the warrants.

No public warrants will be exercisable and we will not be obligated to issue ordinary shares unless the ordinary shares issuable upon such exercise has been registered or qualified or deemed to be exempt under the securities laws of the state of residence of the holder of the warrants. Because the exemptions from qualification in certain states for resales of warrants and for issuances of ordinary shares by the issuer upon exercise of a warrant may be different, a warrant may be held by a holder in a state where an exemption is not available for issuance of ordinary shares upon exercise of the warrant and the holder will be precluded from exercising of the warrant. As a result, the warrants may be deprived of any value, the market for the warrants may be limited and the holders of warrants may not be able to exercise their warrants if the ordinary shares issuable upon such exercise are not qualified or exempt from qualification in the jurisdictions in which the holders of the warrants reside.

We may amend the terms of the warrants that may be adverse to holders with the approval by the holders of a majority of the then outstanding warrants.

Our warrants were issued in registered form under a warrant agreement between Continental Stock Transfer & Trust Company as warrant agent and us. The warrant agreement provides that the terms of the warrants may be amended without the consent of any holder to cure any ambiguity or correct any defective provision, but requires the approval by the holders of a majority of the then outstanding warrants (including the 6,600,000 warrants sold to certain of our insiders in a private placement that occurred simultaneously with the closing of our initial public offering), in order to make any change that adversely affects the interests of the registered holders. Accordingly, we may amend the terms of the warrants in an adverse way to a holder if a majority of the holders approve of such amendment.

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ITEM 4. INFORMATION ON THE COMPANY

A.History and Development of the Company

We were organized on June 17, 2010 as an exempted company under the laws of the Cayman Islands. We were a blank check company formed to acquire through a merger, capital stock exchange, asset acquisition, stock purchase or similar business combination, or control through contractual arrangements, one or more operating businesses. On December 24, 2013, we consummated the merger with Arabella LLC, as more fully described below and, on February 4, 2013, we changed our name from Lone Oak Acquisition Corporation to Arabella Exploration, Inc.

On March 24, 2011, the initial public offering of 4,000,000 of our units was consummated. Each unit issued in the IPO consists of one ordinary share, par value $0.001 per share, and one redeemable warrant. Each redeemable warrant entitles the holder to purchase one ordinary share at a price of $5.00. Prior to the consummation of the IPO, we completed a private placement of 6,600,000 warrants to certain of our initial shareholders generating gross proceeds of $2,310,000. On March 29, 2011, we announced that the underwriters of its IPO exercised their over-allotment option in part, for a total of an additional 106,500 units (over and above the 4,000,000 units sold in the IPO). The 4,106,500 units sold in the IPO, including the 106,500 units subject to the over-allotment option, were sold at an offering price of $8.00 per unit, generating gross proceeds of $32,852,000. A total of $33,462,180, which includes a portion of the $2,310,000 of proceeds from the private placement of warrants to the founding shareholders, was placed in trust. In accordance with the terms of our Articles of Association, until we announced a business combination on September 19, 2012, after which we were no longer permitted to effect such purchases, we purchased 665,000 ordinary shares using an aggregate of $5,189,108 from our trust account. On May 25, 2011, the ordinary shares and warrants underlying the units sold in the IPO began to trade separately on a voluntary basis. We were unable to consummate the transaction announced on September 19, 2012.

Since we would not have been able to complete an acquisition prior to March 24, 2013, the date by which we were required to complete our initial business combination by our Amended and Restated Memorandum and Articles of Association and trust agreement governing the trust account, our board of directors determined that it would be in the best interests of our shareholders for us to extend the terms of the trust agreement governing the trust account for an additional six months (until September 24, 2013) rather than distribute the funds held in the trust account to our public shareholders as required by our Articles of Association, which we refer to as the Initial Extension. In order to effect the Initial Extension, our shareholders approved certain amendments to our Articles of Association and the trust agreement governing the trust account at a special meeting of shareholders held on March 22, 2013. In connection with the Initial Extension, our board of directors determined that it was in our best interest to allow shareholders with the opportunity to redeem their ordinary shares for cash equal to their pro rata share of the aggregate amount then on deposit in the trust account pursuant to an amendment (which was approved as part of the Initial Extension) to the agreement governing the trust account by means of a tender offer, which we refer to as the Initial Extension Tender Offer. Following approval of the Initial Extension, the Initial Extension Tender Offer expired at 11:59 p.m., United States Eastern Time on the evening of March 22, 2013. Pursuant to the terms of the Initial Extension Tender Offer, 2,303,899 of our ordinary shares were validly tendered and accepted for redemption by us for an aggregate purchase price of $18,927,300.

On April 3, 2013, we announced the authorization of a previously announced special cash dividend of $0.10 per outstanding Ordinary Share.  The dividend was paid on April 25, 2013.

Subsequent to the Initial Extension Tender Offer, since we would not have been able to complete an acquisition prior to September 24, 2013, the date by which we were required to complete our initial business combination by our Amended and Restated Memorandum and Articles of Association and trust agreement governing the trust account following the Initial Extension Tender Offer, our board of directors determined that it would be in the best interests of our shareholders for us to extend the terms of the trust agreement governing the trust account for an additional three months (until December 24, 2013) rather than distribute the funds held in the trust account to our public shareholders as required by our Articles of Association, which we refer to as the Subsequent Extension and, together with the Initial Extension, the Extension. In order to effect the Subsequent Extension, our shareholders approved certain amendments to our Articles of Association and the trust agreement governing the trust account at a special meeting of shareholders held on September 10, 2013. In connection with the Subsequent Extension, our board of directors determined that it was in our best interest to allow shareholders with the opportunity to redeem their ordinary shares for cash equal to their pro rata share of the aggregate amount then on deposit in the trust account pursuant to an amendment (which was approved as part of the Subsequent Extension) to the agreement governing the trust account by means of a tender offer, which we refer to as the Subsequent Extension Tender Offer and, together with the Initial Extension Tender Offer, the Extension Tender Offer. Following approval of the Subsequent Extension, the Subsequent Extension Tender Offer expired at 11:59 p.m., United States Eastern Time on the evening of September 19, 2013. Pursuant to the terms of the Subsequent Extension Tender Offer, 20,000 of our ordinary shares were validly tendered and accepted for redemption by us for an aggregate purchase price of $164,307.

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On October 4, 2013, we announced the authorization of a previously announced special cash dividend of $0.10 per outstanding Ordinary Share. The dividend was paid on October 24, 2013.

On October 23, 2013, we entered into an Agreement and Plan of Merger and Reorganization (the “Merger Agreement”) to acquire Arabella LLC (the “Business Combination” or the “Acquisition”). On December 24, 2013, we consummated the Acquisition with Arabella LLC, as more fully described below, and on February 4, 2013, we changed our name from Lone Oak Acquisition Corporation to Arabella Exploration, Inc.

The address of our principal executive offices is 500 W. Texas Avenue, Suite 1450, Midland, Texas 79701.

Agreement and Plan of Merger and Reorganization

On October 23, 2013, we entered into the Merger Agreement to acquire Arabella Exploration, LLC, a Texas limited liability company (“Arabella LLC”), as more fully described below. On December 24, 2013, we consummated the Acquisition with Arabella LLC.

Terms and Conditions of the Merger Agreement

The following is a summary of the material terms of the Merger Agreement.

Acquisition of Arabella LLC

At the closing of the transactions contemplated in the Merger Agreement, Arabella Exploration Corp., our merger subsidiary, merged with and into Arabella LLC, with Arabella LLC as the surviving entity. Pursuant to the Acquisition, all holders of members’ equity of Arabella LLC had their ownership units converted into our ordinary shares, as more fully described below. As a result, following the Acquisition, Arabella LLC became our wholly owned subsidiary and Arabella LLC’s former members have voting and management control of the combined company through their owning a majority of our outstanding ordinary shares and retaining a majority of the board of directors and all of the senior management of the combined company. After termination of the voting agreement that is described below, if all of the outstanding warrants are exercised (and assuming that no additional ordinary shares are issued), the former members of Arabella LLC would not control a majority of our voting power, and, therefore, may not be in a position to maintain control of us after than point.

Acquisition Consideration

Holders of all of the issued and outstanding interests of Arabella LLC immediately prior to the time of the Acquisition had each of their interests of Arabella LLC converted into the right to receive: (i) a proportional amount of 3,125,000 ordinary shares (the “Closing Payment”), plus (ii) a proportional amount of up to 1,705,002 ordinary shares, if any (the “Earnout Payment”), issuable upon the combined company achieving certain thresholds described below.

The Earnout Payment was issued at closing and will be held in escrow until released in accordance with the following:

· One third of the Earnout Payment will be released if the proved reserves of the combined company on December 31, 2014, as per the third party engineering reserve report as of that date, shall have increased 100% from the proved reserves as of the closing, provided, however that the shares shall only be awarded if (A) the finding and development cost per proved Barrel of Oil Equivalent (“BOE”) of the increase in proved reserves is $22 or less and/or if the ratio of finding and development cost to BOE is superior (lower per BOE) or equal to 80% of the Public Peer Set (as defined below) and (B) the combined company’s General & Administrative Cost per BOE of the increase in proved reserves is $12.50 or less and/or if the combined company’s General & Administrative Cost per BOE of the increase is superior (lower per BOE) or equal to 80% of the Public Peer Set. “Public Peer Set” means the following companies, which may be revised from time to time by our board of directors in accordance with the terms of the voting agreement: Oasis Petroleum (OAS); Kodiak Oil & Gas Corp. (KOG); Northern Oil and Gas, Inc. (NOG); Triangle Petroleum Corporation (TPLM); Emerald Oil, Inc. (EOX); Concho Resources, Inc. (CXO); Laredo Petroleum Holdings, Inc. (LPI); Athlon Energy Inc. (ATHL); Diamondback Energy, Inc. (FANG); Clayton Williams (CWEI); and Approach Resources (AREX). The Public Peer Set was selected by Arabella LLC and agreed to by us.

· One third of the Earnout Payment will be released if the proved reserves of the combined company on December 31, 2015, as per the third party engineering reserve report as of that date, shall have increased 66% from the proved reserves as of December 31, 2014, provided, however, that the shares shall only be awarded if (A) the finding and development cost per proved BOE of the increase in proved reserves is $18 or less and/or if the ratio of finding and development cost to BOE superior (lower per BOE) or equal to 80% of the Public Peer Set, and (B) our General & Administrative Cost per BOE of the increase in proved reserves is $6.50 or less and/or if the combined company’s General & Administrative Cost per BOE of the increase is superior (lower per BOE) or equal to 80% of the Public Peer Set.

· One third of the Earnout Payment will be released if the proved reserves of the combined company on December 31, 2016, as per the third party engineering reserve report as of that date, shall have increased 33% from the proved reserves as of December 31, 2015, provided, however, that the shares shall only be awarded if (A) the finding and development cost per proved BOE of the increase in proved reserves is $14 or less and/or if the ratio of finding and development cost to BOE superior (lower per BOE) or equal to 80% of the Public Peer Set, and (B) our General & Administrative Cost per BOE of the increase in proved reserves is $5.00 or less and/or if the combined company’s General & Administrative Cost per BOE of the increase is superior (lower per BOE) or equal to 80% of the Public Peer Set.

If the earnout thresholds are not achieved for any period, the shares for such period will be returned to the combined company for cancellation.

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Board of Directors of the Combined Company; Voting Agreement

The Merger Agreement provided that, upon closing of the Acquisition, four persons on the combined company’s board of directors will be designated by Arabella LLC and three persons will be designated by our founding shareholders. In addition, we and Arabella LLC’s members and certain of our founding shareholders entered into a voting agreement that provides that, for the four year period following the Acquisition, such founding shareholders of ours will designate three persons as nominees to the combined company’s board of directors and Arabella LLC’s former members will designate four persons as nominees to the combined company’s board of directors, and that each of the parties to the voting agreement will take all action necessary to elect such persons to the board of directors of the combined company. The voting agreement will also provide that the company may not take the following actions without the approval of two-thirds of the members of the board of directors and at least one person designated by our founding shareholders voting in favor:

· Issue any ordinary share of the combined company or securities convertible into ordinary shares;

· Repay the loan from Jason Hoisager to Arabella LLC described below;

· Appoint or remove the combined company’s Chief Executive Officer or Chief Financial Officer;

· Amend the Merger Agreement;

· Amend the Public Peer Set;

· Retain an investor relations firm;

· Appoint or hire an employee to provide internal investment relations management; and

· Adopt an equity incentive plan for officers, directors or employees.

Registration Rights

We have agreed to register all shares included in the Closing Payment and the Earnout Payment pursuant to the terms of a Registration Rights Agreement entered into at closing.

Tender Offer

In connection with the Acquisition, we provided our shareholders with the opportunity to redeem those ordinary shares issued in our IPO for cash equal to their pro rata share of the aggregate amount then on deposit in the trust account set up to hold the net proceeds of our IPO pursuant to the Investment Management Trust Agreement, dated as of March 16, 2011, as amended (the “Offer”). The redemption amount in the Offer was $8.21 per share. The Offer was an isolated transaction and was not made pursuant to a plan to periodically increase the proportionate interest of a shareholder in our assets or our earnings and profits.

Pursuant to the terms of the Acquisition, it was a condition to the consummation of the Acquisition that the Offer was conducted in accordance with the terms of the Acquisition and that we shall have accepted the ordinary shares validly tendered and not properly withdrawn pursuant to the Offer and no more than 505,636 of the ordinary shares be validly tendered and not properly withdrawn through this Offer, and, the Offer was subject to the condition that the Acquisition shall have been consummated.

B.       Business Overview

Glossary of Oil and Natural Gas terms:

The following is a description of the meanings of some of the oil and natural gas industry terms used throughout this report:

3-D seismic. Geophysical data that depict the subsurface strata in three dimensions. 3-D seismic typically provides a more detailed and accurate interpretation of the subsurface strata than 2-D, or two-dimensional, seismic.

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Basin. A large natural depression on the earth’s surface in which sediments generally brought by water accumulate.

Bbl. Stock tank barrel, or 42 U.S. gallons liquid volume, used in this report in reference to crude oil or other liquid hydrocarbons.

Bbls/d. Bbls per day.

Bcf.One billion cubic feet of natural gas.

BOE. Barrels of oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of oil. BOE is commonly used by oil and gas companies in their financial statements as a way of combining oil and natural gas reserves and production into a single measure.

BOE/d. BOE per day.

Btu or British thermal unit. The quantity of heat required to raise the temperature of a one pound mass of water from 58.5 to 59.5 degrees Fahrenheit.

Completion. The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

Condensate. A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface temperature and pressure.

Developed acreage. The number of acres that are allocated or assignable to productive wells or wells capable of production.

Development capital.Expenditures to obtain access to proved reserves and to construct facilities for producing, treating, and storing hydrocarbons.

Development well. A well drilled within the proved area of a natural gas or oil reservoir to the depth of a stratigraphic horizon known to be productive.

Deviated well. A well purposely deviated from the vertical using controlled angles to reach an objective location other than directly below the surface location.

Dry hole. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

Economically producible. A resource that generates revenue that exceeds, or is reasonably expected to exceed, the costs of operation. For a complete definition of “economically producible”, refer to the SEC’s Regulation S- X, Rule 4- 10(a)(10).

EUR. Estimated ultimate recovery, the sum of gross reserves remaining as of a given date and the cumulative production as of that date.

Exploratory well. A well drilled to find and produce natural gas or oil reserves not classified as proved, to find a new reservoir in a field previously found to be productive of natural gas or oil in another reservoir or to extend a known reservoir.

F&D Costs. Finding and development costs, capital costs incurred in the acquisition, exploitation and exploration of proved oil and natural gas reserves divided by proved reserve additions and revisions to proved reserves.

Field. An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface area and the underground productive formations. For a complete definition of “field”, refer to the SEC’s Regulation S- X, Rule 4- 10(a)(15).

Formation. A layer of rock that has distinct characteristics that differ from nearby rock.

Fracturing or fracing. The process of creating and preserving a fracture or system of fractures in a reservoir rock typically by injecting a fluid under pressure through a wellbore and into the targeted formation.

GAAP. Accountingprinciples generally accepted in the United States.

Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.

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Held by production acreage. Acreage covered by a mineral lease that perpetuates a company’s right to operate a property as long as the property produces a minimum paying quantity of oil or gas.

Horizontal drilling. A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle with a specified interval.

LOE. Lease operating expense, All direct and allocated indirect costs of lifting hydrocarbons from a producing formation to the surface constituting pat of the current operating expenses of a working interest. Such costs include labor, superintendence, supplies, repairs, maintenance, allocated overhead charges, workover, insurance, and other expenses incidental to production, but exclude lease acquisition or drilling or completion expenses.

MBbls. One thousand barrels.

MBO. One thousand barrels of crude oil, condensate or NGLs.

Mcf. One thousand cubic feet of natural gas.

Mcf/d. Mcf per day.

MBOE. One thousand barrels of oil equivalent.

MMBtu. One million British Thermal Units.

MMcf. One million cubic feet of natural gas.

NGLs. Natural gas liquids, the combination of ethane, butane, isobutene and natural gasolines that when removed from natural gas become liquid under various levels of higher pressure and lower temperature.

Net acres or net wells. The sum of the fractional working interest owned in gross acres or gross wells, as the case may be. For example, an owner who has 50% interest in 100 gross acres owns 50 net acres.

Net revenue interest. An owner’s interest in the revenues of a well after deducting proceeds allocated to royalty and overriding interests.

NYMEX. The New York Mercantile Exchange.

Play. A set of discovered or prospective oil and/or natural gas accumulations sharing similar geologic, geographic and temporal properties, such as source rock, reservoir structure, timing, trapping mechanism and hydrocarbon type.

Plugging and abandonment. Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of all states require plugging of abandoned wells.

Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.

PDNP Reserves. Proved developed non-producing reserves. Hydrocarbons in a potentially producing horizon penetrated by a well bore, the production of which has been postponed pending installation of surface equipment or gathering facilities, or pending the production of hydrocarbons from another formation penetrated by the well bore. The hydrocarbons are classified as proved, but non-producing reserves.

PDP. Proved developed producing.

PDP Reserves. Proved developed producing reserves. Reserves that are being recovered through existing wells with existing equipment and operating methods.

Prospect. A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.

Proved reserves. Those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible - from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. For a complete definition of “proved oil and natural gas reserves”, refer to the SEC’s Regulation S- X, Rule 4- 10(a)(22).

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PUD. Proved undeveloped reserve.

PUD Reserves. Proved undeveloped reserves , proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

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

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

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

PV-10. Present value of future net revenues.

Reasonable certainty. A high degree of confidence. For a complete definition of reasonable certainty, refer to the SEC’s Regulation S- X, Rule 4- 10(a)(24).

Recompletion. The process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production.

Reserves. Estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to market and all permits and financing required to implement the project.

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible hydrocarbons that is confined by impermeable rock or water barriers and is separate from other reservoirs.

Royalty. An interest in an oil and natural gas lease that gives the owner the right to receive a portion of the production from the leased acreage (or of the proceeds from the sale thereof), but does not require the owner to pay any portion of the production or development costs on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.

Spacing. The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres, e.g., 40- acre spacing, and is often established by regulatory agencies.

Stacked pay. Multiple geological zones that potentially contain hydrocarbons and are arranged in a vertical stack.

Stratigraphic play. An oil or natural gas formation contained within an area created by permeability and porosity changes characteristic of the alternating rock layer that result from the sedimentation process.

Structural play. An oil or natural gas formation contained within an area created by earth movements that deform or rupture (such as folding or faulting) rock strata.

TD. Total Depth.

Tight formation. A formation with low permeability that produces natural gas with very low flow rates for long periods of time.

Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.

WTI. West Texas Intermediate crude oil, which is a light, sweet crude oil, characterized by an American Petroleum Institute gravity, or API gravity, 39 and 41, and a sulphur content of approximately 0.4 weight percent that is used as a benchmark for other crude oils.

Wellbore. The hole drilled by the bit that is equipped for oil or gas production on a completed well. Also called well or borehole.

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Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production and requires the owner to pay a share of the costs of drilling and production operations.

Workover. The repair or stimulation of an existing production well for the purpose of restoring, prolonging or enhancing the production of hydrocarbons.

Business

Our wholly-owned subsidiary, Arabella LLC, was established in the State of Texas on December 15, 2008 but did not conduct any material business operations until 2011 with the acquisition of properties in the Permian Basin. Our principal executive offices are located at 500 W. Texas Avenue, Suite 1450, Midland, Texas 79701, and our telephone number is (432) 897-4755. Our Internet website can be found at www.arabellaexploration.com.

As with most oil and gas companies, we have had separate property and management companies. We are the owner of the leases and wells and will maintain this ownership. However, other portions of the business, as is customary, are operated through Arabella Petroleum Company, LLC, an entity owned by Jason Hoisager, our President and CEO. Arabella Petroleum Company, LLC was not included in the Acquisition, and after certain adjustments described below, will cease its affiliation with us. Arabella Petroleum Company, LLC is the management company that has historically maintained the general and administrative and other costs of Arabella LLC.

Arabella Petroleum Company, LLC is the operator of record for our properties with the Texas Railroad Commission. Application will be made to the Railroad Commission to change the operator of record to us. This process will be completed as soon as logistically and reasonably possible. The Merger Agreement provides that Arabella Petroleum Company, LLC may continue to use the name “Arabella” for this purpose only until this process in complete, at which point Arabella Petroleum Company, LLC will cease to use the name.

Overview

We are an independent oil and natural gas company currently focused on the acquisition, development, exploration and exploitation of unconventional, onshore oil and natural gas reserves in the Delaware Basin portion of the Permian Basin in West Texas. The Delaware Basin, which is one of the major producing basins in the United States, is characterized by an extensive production history, a favorable operating environment, mature infrastructure, long reserve life, multiple producing horizons, enhanced recovery potential and a relatively large number of operators.

We began assembly of our core properties in the spring of 2011 with the acquisition of 1,600 gross acres. Subsequently, we acquired approximately 9,282 additional gross acres, which brought our total gross acreage position in the Delaware Basin to 10,882 gross acres, or 5,027 net acres, at December 31, 2012. At the time of these acquisitions, none of the acquired acreage had existing production. At present, Arabella Petroleum Company, LLC, an affiliate of our president, Jason Hoisager, is the operator of record for this acreage. The operation of these properties, along with future properties, will be transferred to a new wholly owned subsidiary of ours as soon as logistically and reasonably feasible within the rules and operations of the Texas Railroad Commission following the Acquisition. As of December 31, 2013, we had participated in 5 gross, 1.25 net, wells, in the Delaware Basin. Of these 5 gross wells, all were completed as producing wells.  Additionally, as of December 31, 2013 we were in the process of drilling our Jackson #1H well.

Our activities are primarily focused on the Wolfcamp and Bone Spring formations, which we refer to collectively as the Wolfbone play. The Wolfbone play is characterized by high oil content and liquids rich natural gas, multiple vertical and horizontal target horizons, extensive production history, long-lived reserves and high drilling success rates.

As of December 31, 2013, our estimated proved oil reserves were 1,540.4 MBbls and our estimated natural gas reserves were 3,197.3 MMcf, based on a reserve report prepared by Williamson Petroleum Consultants, Inc., or WPC, independent reserve engineers. Of the proved oil reserves, approximately 7.7% are classified as proved developed producing, or PDP, the remaining 92.3% are classified as proved undeveloped, or PUD. Of the proved natural gas reserves, approximately 6.6% are classified as PDP and the remaining 93.4% are classified as PUD. PUD reserves included in this estimate are from eleven gross horizontal well locations. As of December 31, 2013, these proved reserves were approximately 74.3% oil and 25.7% natural gas on a BOE basis.

Additionally, we had 2,961.5 MBbls, of probable and 4,092.8 MBbls of possible oil reserves as well as 6,219.1 MMcf of probable and 8,594.9 MMcf of possible gas reserves.

In 2012, we began testing the horizontal well potential of our Delaware Basin acreage. Our first horizontal well was the SM Prewitt #1H in Reeves County with an approximate 4,000 foot lateral in the Wolfcamp C interval. We have a 14.6% working interest in this well. It was completed in December 2012 and had a 24-hour initial production rate of 283 BOE/d and a 30-day average initial production rate of 146 BOE/d, of which 89.0% was oil. Through the end of December 31, 2013, the SM Prewitt #1H had produced a total of 0.482 MBbls of oil and 0.737 MMcf of natural gas. We began a dual lateral completion in our SM Prewitt #1H well by drilling a second lateral stage off of the original vertical well bore in the Wolfcamp A interval but have not completed that lateral.

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Our second horizontal well was the Locker State #1H in Reeves County. Arabella owns a 14.6% working interest in this well. It was completed in March of 2013 in the Wolfcamp D with an approximate 4,000 foot lateral. The production was a peak 24 hour rate of 350 BOE/d and peak 30 day rate of 109 BOE/d, of which 85.0% was oil. Through the end of December 31, 2013, the Locker State #1H had produced a total of 1.011 MBbls of oil and 1.609 MMcf of natural gas.

Our third horizontal well was the Graham #1H, in which Arabella has a 15.6% working interest, which was completed in May 2013. It was completed in the Wolfcamp D with an approximately 4,000 foot lateral. The production was a peak 24 hour rate of 634 BOE/d and a peak 30 day rate of 383 BOE/d, of which 83.0% was oil. Through December 31, 2013, the Graham #1H had produced a total of 3.384 MBbls of oil and 3.693 MMcf of natural gas.

Our fourth horizontal well was the Woods #1H, in which Arabella has a 23.3% working interest, which was completed in August 2013. It was completed in the Wolfcamp B with an approximate 4,000 foot lateral. The production was a peak 24 hour rate of 1,221 BOE/d and a peak 30 day rate of 634 BOE/d, of which 87.0% was oil. Through December 31, 2013, the Woods #1H had produced a total of 8.317 MBbls of oil and 3.129 MMcf of natural gas.

We have drilled one vertical well, the Vastar State #1V, in which Arabella has a 57.1% working interest, which was completed in December 2013.  The Vastar State #1V had not begun significant production as of December 31, 2013 and is currently running production to test zones.

We also were in the process of drilling our sixth well, the Jackson #1H as of December 31, 2013 which was subsequently completed in January of 2014.

Based on the Williamson Reserve Report from current production, EURs for each of the horizontal wells will be in the range of 100 to 600 MBOE.  The table below summarizes Arabella’s working interest and each well’s performance.

Well	Working Interest	Lateral Length(ft)	Completed Formation	Peak Rate 24-hr	24-hr Peak Rate % Oil	Peak Rate 30-day	30-day Peak Rate Percent Oil	EUR BOE
SM Prewitt #1H	14.5500	4,000	Wolfcamp C	283 BOE/day	90%	146 BOE/day	89%	100,000
Locker State #1H	14.5500	4,000	Wolfcamp D	350 BOE/day	84%	109 BOE/day	85%	186,000
Graham #1H	15.5500	4,000	Wolfcamp D	634 BOE/day	82%	383 BOE/day	83%	250,000
Woods #1H	23.2563	4,000	Wolfcamp B	1,221 BOE/day	87%	634 BOE/day	82%	455,000
Vastar State #1V	51.0143	Vertical	Wolfcamp A-D	TBD	TBD	TBD	TBD	TBD
Jackson #1H	58.9023	TBD	TBD	TBD	TBD	TBD	TBD	TBD

The SM Prewitt #1H, Locker State #1H, Graham #1H, Woods #1H, Vastar State #1V and Jackson #1H wells are currently operated by Arabella Petroleum Company, LLC, an affiliate of Jason Hoisager, Arabella’s President. The operation of these wells, along with future wells, will be transferred to a new wholly owned affiliate of Arabella, as soon as logistically and reasonably feasible within the rules and operations of the Texas Railroad Commission.

The production results from the wells in Reeves County, along with the basin wide geoscience and engineering data that Arabella has gathered and analyzed, give Arabella confidence that its acreage in Reeves, Ward, Loving, Pecos and Winkler Counties is prospective in the Wolfcamp A, B, C and D intervals. The data and offset well performance also indicate that all of Arabella’s other Delaware Basin acreage is highly prospective for horizontal drilling and in multiple formations. The formations include not only the Wolfcamp A, B, C and D intervals, but other intervals in the Avalon and Bone Spring formations. However, further testing of these areas and other intervals is necessary to determine their economic potential.

Recent Developments

Subsequent to December 31, 2013, we: (i) completed the Jackson #1H with an estimated peak 24 hour rate of 875 BOE/d of which approximately 82% was oil, (ii) drilled the Emily Bell #1H horizontal well, which is waiting on completion and (iii) drilled our Woods #2H well, which is waiting on completion.

On March 28, 2014 we sold our gross 640, net 329, acres in Loving County and on April 23, 2014 we sold our gross 640, net 313, acres in Pecos County; both sales were to fund operations and to focus on the Company’s more core drilling locations.

On May 1, 2014 Arabella received a loan from Hauser Holdings, LLC an affiliate of Richard Hauser, one of our directors.  The $800,000 loan is due August 31, 2014 and bears an interest rate of 10% per annum.

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Our Business Strategy

Our business strategy is to increase stockholder value through the following:

● Grow production and reserves by developing Arabella’s oil-rich resource base. Arabella intends to actively drill and develop its acreage base in an effort to maximize its value and resource potential. Through the conversion of its undeveloped reserves to developed reserves, Arabella will seek to increase Arabella’s production, reserves and cash flow while generating favorable returns on invested capital. As of December 31, 2013, Arabella had identified 426 potential horizontal drilling locations on Arabella’s acreage in the Delaware Basin based on an industry standard 160-acre spacing. Arabella was operating one horizontal drilling rig as of December 31, 2013.

● Optimize hydrocarbon recovery through horizontal drilling and increased well density. Arabella closely monitors industry trends with respect to higher well density, which could increase the recovery factor per section and enhance returns since infrastructure is typically in place. Further, Arabella believes there are opportunities to target various intervals in the Wolfbone play with horizontal wells. Arabella’s initial horizontal focus has been on the Wolfcamp A, B, C and D intervals in Reeves County. Arabella’s first four horizontal wells were completed in 2013 and had lateral lengths of approximately 4,000 feet. Currently, Arabella is drilling a dual lateral horizontal, which involves reentering a well with the original lateral being in the Wolfcamp C, and then adding an additional lateral in the Wolfcamp A above it. The production will be comingled. Arabella expects that the “stacked” lateral wells will result in higher per well recoveries and lower development costs per BOE. Arabella’s future horizontal drilling program is designed to further capture the upside potential that may exist on Arabella’s properties. Arabella also believe Arabella’s “stacked” horizontal drilling program may significantly increase Arabella’s recoveries per section as compared to drilling a single horizontal well per vertical wellbore. Horizontal drilling may also be economical in areas where vertical drilling is currently not economical or logistically viable. In addition, Arabella believes increased well density opportunities may exist across Arabella’s acreage base.

● Leverage Arabella’s experience operating in the Permian Basin. Arabella’s executive team, which has an average of approximately 11 years of industry experience per person and significant experience in the Permian Basin, intends to continue to seek ways to maximize hydrocarbon recovery by refining and enhancing Arabella’s drilling and completion techniques. Arabella’s focus on efficient drilling and completion techniques, and the reduction in time to market with Arabella’s product, is an important part of the continuous drilling program Arabella has planned for Arabella’s significant inventory of identified potential drilling locations. In addition, Arabella believes that the experience of Arabella’s executive team in deviated and horizontal drilling and completions should help reduce the execution risk normally associated with these complex well paths. Additionally, Arabella’s completion techniques are continually evolving as Arabella evaluates hydraulic fracturing practices that may potentially increase recovery and reduce completion costs. Arabella’s executive team regularly evaluates Arabella’s operating results against those of other operators in the area in an effort to benchmark Arabella’s performance against the best performing operators and evaluate and adopt best practices.

● Pursue strategic acquisitions with exceptional resource potential. Arabella has a proven history of acquiring leasehold positions in the Delaware Basin that have substantial oil-weighted resource potential and can achieve attractive returns on invested capital. Arabella’s executive team, with its extensive experience in the Permian Basin, has what Arabella believes is a competitive advantage in identifying acquisition targets and a proven ability to evaluate resource potential. Arabella intends to continue to pursue acquisitions that meet Arabella’s strategic and financial targets.

● Pursue additional drilling/development financing to accelerate additional drilling operations. Arabella has engaged investment banks to assist Arabella in raising up to $100 million of debt to accelerate Arabella’s drilling operations. Arabella has received substantially positive initial feedback from private capital providers and anticipates receiving financing proposals in the second quarter of 2014.  Arabella anticipates closing on financing in either the late second quarter or third quarter of 2014.

● Acquire additional development acreage through “farm in” opportunities. Because of Arabella’s management team’s strong drilling and development track record and its deep knowledge of the Delaware Basin, Arabella believes that it will be able to increase its acreage position at a better than market cost through “farm in” arrangements with other leaseholders in the Delaware Basin. There are a number of individuals and entities that have leased acreage in the Delaware Basin that do not have the technical or capital capacity to drill and develop their acreage. Arabella’s demonstrated technical ability to drill complicated horizontal wells, manage multi rig drilling programs, design and execute hydraulic fracture stimulation, and optimize production and capital efficiency enhances Arabella’s position amongst its peers in the Delaware Basin. In many leasehold positions, if the current lease holder does not drill a well on the acreage within the term of the lease (typically within the next two and one half years), the current leaseholder will be contractually compelled to surrender the lease. It is more advantageous to the current holder of the lease, assuming they do not have the ability for whatever reason to drill or develop the lease, to allow Arabella to drill and develop a portion of their lease as the Operator through a structured transaction wherein the current holder receives a carried interest in the lease instead of paying a large cash sum to renew the lease. Arabella’s research indicates in excess of 100,000 acres of potential “farm in” opportunities in its target area.

Our Strengths

We believe that the following strengths will help us achieve our business goals:

● Oil rich resource base in one of North America’s leading resource plays. All of Arabella’s leasehold acreage is located in one of the most prolific oil plays in North America, the Delaware Basin portion of the Permian Basin in West Texas. The majority of Arabella’s current properties are well positioned in the core of the Wolfbone play. Arabella believes that its historical horizontal development success will be complemented with Arabella’s “stacked” horizontal drilling locations that could ultimately translate into an increased recovery factor on a per section basis. Arabella’s production during 2013 was approximately 92% oil and 8% natural gas. This oil exposure allows Arabella to benefit from their currently more favorable prices as compared to natural gas.

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● Multi-year drilling inventory in one of North America’s leading oil resource plays. Arabella has identified a multi-year inventory of potential drilling locations for its oil-weighted reserves that it believes provides attractive growth and return opportunities. As of December 31, 2013, based on Arabella’s initial results and those of other operators in the area to date, combined with Arabella’s interpretation of various geologic and engineering data, Arabella has identified 426 potential horizontal locations on Arabella’s acreage. Of the potential 426 horizontal locations, eleven of them are horizontal PUD’s. These locations exist across most of Arabella’s acreage blocks and in multiple horizons. Of the 426 potential horizontal locations, 71 are in the Wolfcamp A horizon, 71 are in the Wolfcamp B horizon, 71 are in the Wolfcamp C and 71 are in the Wolfcamp D and the remainder in the various Bone Spring horizons. Arabella has not assigned any horizontal locations to the Delaware interval but believe that it may also have development potential. Arabella’s current horizontal location count is based on 1,320 foot spacing between wells. The ultimate inter-well spacing may be closer than 1,320 feet, which would result in a higher location count.

● Experienced, and proven management team. Arabella’s executive team has an average of approximately 11 years of industry experience per person, most of which is focused on resource play development. This team has a track record of executing on multi-rig development drilling programs and extensive experience in the Permian Basin. In addition, Arabella’s executive team has significant experience with both drilling and completing horizontal wells as well as horizontal well reservoir and geologic expertise, which will be of strategic importance as Arabella expands its horizontal drilling activity. Mr. Bill Elliott was added to the Arabella team in June of 2012. At his most recent prior employer (Oxy), he managed 22,000 producing wells and in excess of 600 people. He was responsible for all the production for the wells in the Permian Basin (on the primary side). Mr. Chad Elliott started his career in drilling in 1999 with Oxy, specializing in horizontal drilling. In his career, he has either drilled or supervised the drilling of over 1,200 vertical wells, 300 horizontal wells and 11 multi-lateral wells.

● Favorable and stable operating environment. Arabella has focused its drilling and development operations in the Permian Basin, one of the oldest hydrocarbon basins in the United States, with a long and well-established production history and developed infrastructure. With approximately 380,000 wells drilled in the Permian Basin since the 1940s, Arabella believes that the geological and regulatory environment is more stable and predictable, and that Arabella is faced with fewer operational risks in the Permian Basin, as compared to emerging hydrocarbon basins.

● High degree of operational control. By the third quarter of 2014, Arabella will be the operator of all of its Permian Basin acreage. This operating control allows Arabella to better execute on its strategies of enhancing returns through operational and cost efficiencies and increasing ultimate hydrocarbon recovery by seeking to continually improve its drilling techniques, completion methodologies and reservoir evaluation processes. Additionally, as the operator of substantially all of Arabella’s acreage, Arabella retains the ability to adjust its capital expenditure program based on commodity price outlooks. This operating control also enables Arabella to obtain data needed for efficient exploration of horizontal prospects.

● Financial flexibility to fund expansion. Arabella will seek to maintain financial flexibility to allow Arabella to actively develop Arabella’s drilling, exploitation and exploration activities in the Wolfbone play and maximize the present value of Arabella’s oil-weighted resource potential.

Review of Exploration, Exploitation and Development Activities

Area History

Location and Land – Delaware Basin Located in the Western half of the Permian Basin

The Permian Basin area covers a significant portion of western Texas and eastern New Mexico and is considered one of the major producing basins in the United States. Arabella acquired approximately 1,600 gross acres directly from mineral owners in West Texas (near Pecos, Texas) in the Delaware Basin portion of the Permian Basin in 2011. Subsequently, Arabella acquired approximately 9,282 additional gross acres, which brought Arabella’s total gross acreage position in the Delaware Basin to approximately 10,882 gross acres at December 31, 2013. Since Arabella’s initial acquisition, and through December 31, 2013, Arabella drilled or participated in the drilling of 4 gross horizontal wells and one gross vertical well (with one of these wells being a dual lateral horizontal well) on Arabella’s leasehold in this area, exclusively targeting the Wolfbone play of the Delaware Basin. Arabella is the operator of approximately 99% of Arabella’s acreage.

Delaware Basin Development History

Arabella’s proven reserves are located in the Permian Basin of West Texas and focused on the Delaware Basin of West Texas and Southeast New Mexico. We believe Arabella has been instrumental in the development of the Wolfbone unconventional play. For example, Arabella has leased more than 125,000 acres in the play beginning in 2006 and Rich Masterson, Arabella’s geologist, worked with a number of development companies in the early years of the play. The Wolfbone consists of Wolfcampian age rocks deposited in the deep Delaware trench, which continued to fill into Leonardian time in the Bone Spring Formations. The play was initiated when geologists identified that well samples and mudlog oil and gas shows were in rocks not known for reservoir characteristics, but were consistent and correlative over expansive portions of the Delaware Basin. The rock information was from older deeper gas wells drilled for Devonian, Silurian and Ordovician age structural entrapment. During drilling for the deeper target formations, the wells would regularly encounter oil on the pits and high gas readings that indicated oil and gas saturation with high bottom hole pressures. These shows were present in the 4,000 feet of silty shales in the Basin fill above the deeper targeted formations. This shallower rock was considered at the time to be another non-productive localized lens and only occasionally would be completed with a small acid treatment to hold acreage over the conventional deeper gas plays. A few fields were found where very tight sandstones were deposited, incased in the silty shales. The Gomez Wolfcamp Field was discovered in 1976 and the wells produced at far higher productive rates than the sandstone reservoir had capacity and capability. The poor fracture stimulations during the 1970s still drained a portion of the surrounding siltstones. Shell Oil , Texaco and later Tenneco tried and successfully extended the Wolfcamp sand play. Most of the area was condemned as a reservoir as being too tight and argillaceous but most geologists recognized the Wolfcamp as being the thickest source rock for the Basin.

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In 2004, the Barnett Shale formation was being developed using large slick water fracture stimulation to extract gas from this extremely tight shale. Chesapeake, Petrohunt, EOG and others attempted to establish production from the Barnett in the Delaware Basin, where they encountered good gas shows. After several attempts, the Barnett in the Delaware Basin was found to be too tight to produce economically. However, these operators did bring the large frac jobs and horizontal drilling to West Texas. Zones like the 3rd , or basal, Bone Spring initially was attempted in the War-Wink West Field northwest of Pyote, Texas. In 2005, Cimarex reentered conventionally produced thin silty sandstones and drilled out horizontally in small hole sizes and had some economic success, completing the horizontal with multi-stage frac jobs. This developed into an extensive expansion of the Upper 3rd Bone Spring, but the understanding of the relationship between the 3rd Bone Spring sand reservoir and the organic rich silts of the 2nd Bone Spring and Wolfcamp was still very limited.

In late 2009, J. Cleo Thompson and Eagle Oil & Gas began to test the Bone Spring in vertical wells in Reeves County and found it productive. Later that year J. Cleo Thompson tested only the Wolfcampian silts, tight limes, shales and sandstones in the Floyd 43 well eight miles southeast of Pecos, Texas. This well proved that the entire Upper Wolfcampian section of approximately 1,000 feet in thickness was productive for oil and gas, and that it was overpressured. Further, development and denser spacing of the vertical multi-stage frac designs improved the productivity of the wells. New frac designs with higher pump rates have also improved production. Petrophysical information from production tests, mudlogs, cores and new electric log combinations (CMR, Triple Combo, Sonic Scanner, Imaging tools and Lithoscanner) helped to evaluate and segregate the better rock from the poorer and identify true frac boundaries. Recipes for proper reservoir characteristics are now better understood. The better horizontal targets are selected for reservoir quality and capability of staying in the objective zones while drilling horizontally. Future study to understand the frac geometries will help determine vertical distances between the horizontals. At least 6 separate horizontal targets per 160 acre spacing have been identified in most of the central Delaware Basin and with at least four targets identified on the Basin fringes.

Geology

Intense plate tectonics created the deep trench of the Delaware Basin during late Mississippian through Pennsylvanian time. Left lateral faulting and resulting subsidence in Basin filling during late Pennsylvanian and Early Wolfcampian time set the stage for the deposition of the Wolfbone play.

The Delaware Basin has produced oil and gas from the Permian through Ellenberger age rocks. To the east is the abrupt facies change into the shelf edge carbonates in the Bone Spring and the 6,000 feet of abrupt structural relief and facies change of the Wolfcamp. To the west of Pecos, Texas is the northwest striking and gently eastern dipping monocline of the very asymmetrical Delaware Basin.

The Wolfcampian age portion of the Wolfbone was deposited predominately in a starved trench with little to no sunlight or oxygen. Having little tectonic or depositional influences during deposition preserved this reducing environment. Most of the basinal fill is windblown silts and fine silts caught in off shore currents. Whole core data has backed this interpretation. Pelagic algal and other organic skeletal debris form the makeup of the thin limes that are interbedded with the silts. Occasionally near the shelf edges, short periods of carbonate breccia and conglomerates occur locally. Often the breccias consist of deep water Crinoid fragments. The Basin filled like a bowl with a thick center, an abrupt eastern rim and a gently rising western flank. The geochemistry of the organic matter within the reducing environment and depth of burial created a thick succession of bitumen rich rock that reached a thermal maturity for oil. Interbedded with the silts are high clay rich shales and siliceous limestones that are impermeable and create seals that help concentrate pressure and high TOC intervals below the seals. The intervals are over pressured (pg=0.71 to 0.80). The seals are thin and are breached if near high-energy depositional facies or intense fracturing due to deeper-seated faulting. The better wells are in the down thrown fault blocks or grabens.

The siltstones that exhibit the best reservoir quality have low clay content, calcite cement for brittleness, high TOCs, and larger pore throat sizes. These qualities can be recognized in the Schlumberger logging suite.

Mudlog shows on the gas chromatograph combined with oil cuts and insoluble residues also corroborate the electric log suite. Sidewall coring and whole core analysis tied to the logging suites also better define cut offs for reservoir parameters. Multiple horizontal targets are selected from these studies. All the four horizontal targets attempted to date are successful oil and gas completions. Arabella is currently drilling in or producing from all four of the horizontal targets at depths of 10,000 to 10,700 feet.

The Bone Spring deposition is similar to the Wolfcampian although at a shallower (8,000 to 11,100 feet) depth. The Bone Spring is divided into three Geological Formations. The deepest and oldest is the 3rd Bone Spring deposited above the Wolfcamp. It has been extensively horizontalled throughout the Delaware Basin with some production communication with the Upper Wolfcampian producing horizon. The top of the 3rd Bone Spring has an ash fall structural marker that occurs in all the basinal wells. The 3rd Bone Spring produces from a series of dolomite cemented silty sands and vertically adjoining silty shales. It is slightly overpressured (pg. of 0.68 to 0.72).

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The 2nd Bone Spring Siltstone overlies the Third Bone Spring marker. It is 300 feet thick and mostly overpressured (pg.= 0.70). It has been tested vertically and horizontally from New Mexico to Balmorhea, Texas. Some of the most productive tests in this zone lie near Arabella acreage located southeast of Pecos. Horizontal wells have initially produced at rates of over 1,200 BOE/day.

The 1st Bone Spring produces from sandy siltstones and carbonate detrital interbedded with organic rich shales. It is being extensively developed from two intervals that are locally named the Upper and Lower Avalon. The upper pay is about 150 feet below the top of the 1st Bone Spring Lime. The Lower Avalon is 500 feet below the top of the 1st Bone Spring Lime and appears to date to be the better producer. A majority of the wells seem to be producing from a gas condensate reservoir. The two zones are present throughout the Delaware Basin. A good cement job is needed so that frac communication doesn’t occur with overlying Brushy Canyon sands, which can contain water. These zones have higher porosities and permeabilities than the lower Bone Spring zones and also have lower frac gradients.

Production Status

During the year ended December 31, 2013, there was production from the SM Prewitt #1H, Locker State #1H, Graham #1H and Woods #1H wells.  The Vastar State #1V was completed as of December 31, 2013 and flowing back, but had not yet produced significant oil or gas. Arabella currently has six producing wells (including the Vastar State #1) and is drilling two additional wells.

Facilities

Arabella’s land oil and gas processing facilities are typical of those found in the Permian Basin. Arabella’s facilities located at well locations include storage tank batteries, oil/gas/water separation equipment and pumping units.

Future Activity

During 2014, Arabella plans to drill approximately 14 gross horizontal wells on Arabella’s acreage. Arabella estimates that Arabella’s capital expenditures for 2014 will be between $50 million and $75 million, which includes costs for infrastructure and non-operated wells, but does not include the cost of any land acquisitions.

Oil and Gas Data

Proved Reserves

SEC Rule-Making Activity

In December 2008, the Securities and Exchange Commission, or the SEC, released its final rule for “Modernization of Oil and Gas Reporting.” These rules require disclosure of oil and gas proved reserves by significant geographic area, using the arithmetic 12-month average beginning-of-the-month price for the year, as opposed to year-end prices as had previously been required, unless contractual arrangements designate the price to be used. Other significant amendments included the following:

● 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 they are scheduled to be drilled within the next five years, unless the specific circumstances justify a longer time. Please see Regulation S-X Rule 4-10(a)(22) (“Proved Oil and Gas Reserves”) and Rule 4-10(a)(31) (“Undeveloped Oil and Gas Reserves”) for further information on these guidelines.

● 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. Arabella is also required to provide a general discussion of Arabella’s 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.

Arabella adopted the rules effective December 31, 2009, as required by the SEC.

Evaluation and Review of Reserves

Arabella’s historical reserve estimates were prepared by Williamson Petroleum Consultants, Inc. (“WPC”) as of December 31, 2013 and December 31, 2012, in each case with respect to Arabella’s assets in the Permian Basin. The proportion of Arabella’s total reserves covered by the reports is 100%. The assumptions, data, methods and procedures employed by WPC are appropriate for the purpose served by the reports and WPC has used all methods and procedures as it considered necessary under the circumstances to prepare the reports.

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WPC is an independent petroleum engineering firm registered in the state of Texas. The technical persons responsible for preparing Arabella’s proved reserve estimates meet the requirements with regards to qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. WPC is an independent third-party engineering firm and owns no interest in any of Arabella’s properties or is employed by Arabella on a contingent basis.

Roy C. Williamson, Jr. is the Chief Executive Officer and President of WPC and is the technical person primarily responsible for evaluating the proved reserves covered by this report. Mr. Williamson has 57 years’ experience in evaluating oil and gas reserves, including 46 years’ experience as a consulting reservoir engineer. Mr. Williamson holds a Bachelor of Science Degrees in Petroleum Engineering and Geological Engineering from the University of Oklahoma. He is a Registered Professional Engineer in the States of Texas and Colorado. He is a member of the Society of Petroleum Engineers, the Society of Petroleum Evaluation Engineers, the Society of Independent Professional Earth Scientists, and the Society of Petrophysicists and Well Log Analysts.

Under SEC rules, proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. If deterministic methods are used, the SEC has defined reasonable certainty for proved reserves as a “high degree of confidence that the quantities will be recovered.” All of Arabella’s 2012 and 2013 proved reserves were estimated using a deterministic method. The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions established under SEC rules. The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods, (2) volumetric-based methods and (3) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. The proved reserves for Arabella’s properties were estimated by performance methods, analogy or a combination of both methods. Approximately 85% of the proved producing reserves attributable to producing wells were estimated by performance methods. These performance methods include, but may not be limited to, decline curve analysis, which utilized extrapolations of available historical production and pressure data. The remaining 15% of the proved producing reserves were estimated by analogy, or a combination of performance and analogy methods. The analogy method was used where there were inadequate historical performance data to establish a definitive trend and where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate. All proved developed non-producing and undeveloped reserves were estimated by the analogy method.

To estimate economically recoverable proved reserves and related future net cash flows, WPC considered many factors and assumptions, including the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and the SEC pricing requirements and forecasts of future production rates. To establish reasonable certainty with respect to Arabella’s estimated proved reserves, the technologies and economic data used in the estimation of Arabella’s proved reserves included production and well test data, downhole completion information, geologic data, electrical logs, radioactivity logs, core analyses, available seismic data and historical well cost and operating expense data.

Arabella maintains a staff of geoscience professionals who worked closely with Arabella’s independent reserve engineers to ensure the integrity, accuracy and timeliness of the data used to calculate Arabella’s proved reserves relating to Arabella’s assets in the Permian Basin. Arabella’s internal technical team members met with Arabella’s independent reserve engineers periodically during the period covered by the reserve report to discuss the assumptions and methods used in the proved reserve estimation process. Arabella provides historical information to the independent reserve engineers for Arabella’s properties such as ownership interest, oil and gas production, well test data, commodity prices and operating and development costs. Arabella’s geoscience staff has an average of approximately 39 years of industry experience per person. Arabella’s technical staff uses historical information for Arabella’s properties such as ownership interest, oil and gas production, well test data, commodity prices and operating and development costs.

The preparation of Arabella’s proved reserve estimates are completed in accordance with Arabella’s internal control procedures. These procedures, which are intended to ensure reliability of reserve estimations, include the following:

● review and verification of historical production data, which data is based on actual production as reported by Arabella;

● preparation of reserve estimates by Arabella’s management team or under their direct supervision;

● direct reporting responsibilities by Arabella’s management team to Arabella’s Chief Executive Officer;

● verification of property ownership by Arabella’s land department; and

● no employee’s compensation is tied to the amount of reserves booked.

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The following table presents Arabella’s estimated net oil and natural gas reserves as of December 31, 2013, December 31, 2012 and December 31, 2011, based on the reserve report prepared by WPC, and such reserve reports have been prepared in accordance with the rules and regulations of the SEC. Although a specific lease may not have proved reserves, probable and possible reserves were assigned on the leases based on the interpretation of geologic and engineering data of the widespread productive area of the formations. Reserves assigned as probable or possible reflect the reduced certainty of the wells to be drilled. Probable and possible reserves assigned were estimated using SEC rules 4-10(a)(17) and (18) of Regulation S-X. All Arabella’s proved reserves included in the reserve reports are located in North America.

	Historical(1)
	December 31, 2013			December 31, 2012			December 31, 2011
Estimated proved developed reserves:
Oil (MBbls)		118.5			7.7			-
Natural gas (MMcf)		211.4			6.4			-
Natural gas liquids (MBbls)		-			-			-
Total (MBOE)		153.7			8.8			-
Estimated proved undeveloped reserves:
Oil (MBbls)		1,421.9			158.6			13.7
Natural gas (MMcf)		2,986.0			370.8			-
Natural gas liquids (MBbls)		-			-			-
Total (MBOE)		1,919.6			222.1			13.7
Estimated net proved reserves:
Oil (MBbls)		1,540.4			166.3			13.7
Natural gas (MMcf)		3,197.3			377.2			-
Natural gas liquids (MBbls)		-			-			-
Total (MBOE)		2,073.2			229.2			13.7
Percent proved developed		7.4	%		3.8	%		-
Probable developed reserves
Oil (MBbls)		—			—			—
Natural gas (MMcf)		—			—			—
Natural gas liquids (MBbls)		—			—			—
Total (MBOE)		—			—			—
Probable undeveloped reserves
Oil (MBbls)		2,961.5			1,414.8			—
Natural gas (MMcf)		6,219.1			1,980.7			—
Natural gas liquids (MBbls)		—			—			—
Total (MBOE)		3,998.0			1,744.9			—
Possible developed reserves
Oil (MBbls)		—			—			—
Natural gas (MMcf)		—			—			—
Natural gas liquids (MBbls)		—			—			—
Total (MBOE)		—			—			—
Possible undeveloped reserves
Oil (MBls)		4,092.8			297.9			149.8
Natural gas (MMcf)		8,594.9			417.1			208.5
Natural gas liquids (MBbls)		—			—			—
Total (MBOE)		5,525.3			367.4			183.6

(1) Estimates of reserves as of December 31, 2013, 2012 and 2011 were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month within the 12-month periods ended December 31, 2013, 2012 and 2011 respectively, in accordance with revised SEC guidelines applicable to reserves estimates as of the end of such periods. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for undeveloped acreage. The reserve estimates represent Arabella’s net revenue interest in Arabella’s properties. Although Arabella believes these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates.

The foregoing reserves are all located within the continental United States. Reserve engineering is a subjective process of estimating volumes of economically recoverable oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. As a result, the estimates of different engineers often vary. In addition, the results of drilling, testing and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered. Estimates of economically recoverable oil and natural gas and of future net revenues are based on a number of variables and assumptions, all of which may vary from actual results, including geologic interpretation, prices and future production rates and costs. Arabella has not filed any estimates of total, proved net oil or natural gas reserves with any federal authority or agency other than the SEC.

Proved Undeveloped Reserves (PUDs)

As of December 31, 2013, Arabella’s proved undeveloped reserves totaled 1,421.9 MBbls of oil and 2,986.0 MMcf of natural gas for a total of 1,919.6 MBOE. PUDs will be converted from undeveloped to developed as the applicable wells begin production.

Changes in PUDs that occurred during 2013 were primarily due to:

● additions of 1,618.4 MBOE attributable to extensions resulting from strategic drilling of wells by Arabella to delineate Arabella’s acreage position; and

● the conversion of approximately 144.9 MBOE from PUDs into proved developed reserves from drilling of wells.

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Costs incurred relating to the development of PUDs were approximately $12.2 million during 2013. Estimated future development costs relating to the development of PUDs, including existing PUDs and future PUDs developed from drilling or acquired, are projected to be approximately $50 million in 2014, $100 million in 2015, $150 million in 2016 and $150 million in 2017. As Arabella continues to develop Arabella’s properties and have more well production and completion data, Arabella believes Arabella will continue to realize cost savings and experience lower relative drilling and completion costs as Arabella convert PUDs into proved developed reserves in upcoming years. These anticipated lower drilling and completion costs are not incorporated into Arabella’s proved reserve estimates as of December 31, 2013.

The following table shows how our total net proved reserves increased from December 31, 2012 to December 31, 2013.

	Amount of increase (decrease)
Method of Increase (Decrease)	Oil (Bbls)			Natural Gas (Mcf)
Production		(13,915	)		(11,048	)
Purchase and discoveries of minerals in place		1,216,611			2,521,015
Revisions		171,385			310,181

All of Arabella’s PUD drilling locations are scheduled to be drilled prior to the end of 2017. As of December 31, 2013, none of Arabella’s total proved reserves were classified as proved developed non-producing.

Oil and Gas Production Prices and Production Costs

Production and Price History

The following table sets forth information regarding Arabella’s net production of oil, natural gas and natural gas liquids, all of which is from the Permian Basin in West Texas, and certain price and cost information for each of the periods indicated

	Historical
	December 31, 2013		December 31, 2012		December 31, 2011
Production Data:
Oil (Bbls)		13,915		678		145
Natural gas (Mcf)		11,048		1,338		392
Combined volumes (BOE)		15,756		901		210
Daily combined volumes (BOE/d)		43.2		2.5		0.6
Average Prices(1):
Oil (per Bbl)	$	96.45	$	86.78	$	89.56
Natural gas (per Mcf)		6.88		5.26		9.07
Combined (per BOE)		90.01		73.11		78.77
Average Costs (per BOE):
Lease operating expense	$	9.65	$	13.90	$	27.25
Production Taxes		4.06		3.52		3.90
Production Taxes as a % of sales		4.5		4.8		4.9
Depreciation, depletion and amortization		29.78		41.80		33.50
General and Administrative		34.54		142.50		79.10

 (1) The average prices per barrel of oil and per BOE were $89.56 and $78.77, respectively, during the year ended December 31, 2011, $86.78 and $73.11, respectively, during the year ended December 31, 2012, and $96.45 and $90.01, respectively, during the year ended December 31, 2013.

Productive Wells

As of December 31, 2013, Arabella owned an average 25% working interest in 5 gross (1.25 net) productive wells. Productive wells consist of producing wells and wells capable of production, including oil wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which Arabella has an interest, and net wells are the sum of Arabella’s fractional working interests owned in gross wells.

Acreage

The following table sets forth information as of December 31, 2012 and December 31, 2013 relating to Arabella’s leasehold acreage:

	Developed Acreage(1)		Undeveloped Acreage(2)		Total Acreage
Basin	Gross(3)	Net(4)	Gross(3)	Net(4)	Gross(3)	Net(4)
Permian	1,920.00	570.18	9,270.93	4,856.20	11,190.93	5,426.38

(1) Developed acres are acres spaced or assigned to productive wells and do not include undrilled acreage held by production under the terms of the lease.

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(2) Undeveloped acres are acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas, regardless of whether such acreage contains proved reserves.

(3) A gross acre is an acre in which a working interest is owned. The number of gross acres is the total number of acres in which a working interest is owned.

(4) A net acre is deemed to exist when the sum of the fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.

Arabella’s gross and net acreage figures are as follows for each of the following counties:

County	Gross Acreage	Net Acreage
Reeves County	8,331.9		3,469.9
Ward County	640.0		309.0
Loving County	640.0		329.0
Winkler County	630.0		630.0
Pecos County	640.0		289.0

Undeveloped acreage expirations

Leases comprising the undeveloped acreage set forth in the table above will expire at the end of their respective primary terms unless production from the leasehold acreage has been established prior to such date, in which event the lease will remain in effect until the cessation of production. The following table sets forth the gross and net undeveloped acreage, as of December 31, 2013, that will expire over the next five years unless production is established within the spacing units covering the acreage or the lease is renewed or extended under continuous drilling provisions prior to the primary term expiration dates. No PUD reserves were scheduled in our December 31, 2013 reserve report to be drilled after the lease expiration.

	2014				2015				2016				2017				2018
Permian Basin	Gross		Net		Gross		Net		Gross		Net		Gross		Net		Gross	Net
December 31, 2013		2,840.0		1,833.1		4030.9		2,107.0		160.0		160.0		640.0		287.6

Drilling Results

The following table sets forth information with respect to the number of wells completed during the periods indicated. Each of these wells was drilled in the Delaware Basin of West Texas. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled, quantities of reserves found or economic value. Productive wells are those that produce commercial quantities of hydrocarbons, whether or not they produce a reasonable rate of return.

	December 31, 2013				December 31, 2012				December 31, 2011
	Gross		Net		Gross		Net		Gross		Net
Development:
Productive		-		-		-		-		-		-
Dry		-		-		-		-		-		-
Exploratory:
Productive		5.0		1.3		2.0		0.2		-		-
Dry		-		-		-		-		-		-
Total:
Productive		5.0		1.3		2.0		0.2		-		-
Dry		-		-		-		-		-		-

As of December 31, 2013, Arabella had 1 gross (0.53 net) well in the process of drilling, completing or dewatering or shut in awaiting infrastructure that is not reflected in the above table.

Title to Properties

As is customary in the oil and gas industry, Arabella initially conducts only a cursory review of the title to Arabella’s properties. At such time as Arabella determines to conduct drilling operations on those properties, it conducts a thorough title examination and perform curative work with respect to significant defects prior to commencement of drilling operations. To the extent title opinions or other investigations reflect title defects on those properties, Arabella is typically responsible for curing any title defects at its own expense. Arabella generally will not commence drilling operations on a property until Arabella has cured any material title defects on such property. Arabella has obtained title opinions on all of Arabella’s producing properties and believes that Arabella has satisfactory title to Arabella’s producing properties in accordance with standards generally accepted in the oil and gas industry. Prior to completing an acquisition of producing oil and natural gas leases, Arabella performs title reviews on the most significant leases and, depending on the materiality of properties, Arabella may obtain a title opinion, obtain an updated title review or opinion or review previously obtained title opinions. Arabella’s oil and natural gas properties are subject to customary royalty and other interests, liens for current taxes and other burdens which Arabella believes do not materially interfere with the use of or affect Arabella’s carrying value of the properties.

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Marketing and Customers

We market our oil and natural gas production from properties we own. We sell our oil and natural gas to purchasers at market prices. Some of our natural gas contracts have terms of greater than twelve months and all of our oil contracts have terms of twelve months or less.

We normally sell production to a relatively small number of customers, as is customary in the exploration, development and production business.  For 2013, two purchasers accounted for a significant amount of our revenue: Sunoco Partners (78%) and Enterprise Crude Oil, LLC (10%).  If a major customer decided to stop purchasing oil and natural gas from us, revenue could decline and our operating results and financial condition could be harmed in the applicable period. However, based on the current demand for oil and natural gas, and the availability of other purchasers, we believe that the loss of any one or all of our major purchasers would not have a material adverse effect on our financial condition and results of operations, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers.

Competition

The oil and natural gas industry is intensely competitive, and Arabella competes 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 to define, evaluate, bid for and purchase a greater number of properties and prospects than Arabella’s financial 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. Arabella’s larger or more integrated competitors may be able to absorb the burden of existing, and any changes to, federal, state and local laws and regulations more easily than Arabella can, which would adversely affect Arabella’s competitive position. Arabella’s ability to acquire additional properties and to discover reserves in the future will be dependent upon Arabella’s ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, because Arabella has fewer financial and human resources than many companies in Arabella’s industry, Arabella may be at a disadvantage in bidding for exploratory prospects and producing oil and natural gas properties. Further, oil and natural gas compete with other forms of energy available to customers, primarily based on price. These alternate forms of energy include electricity, coal and fuel oils. Changes in the availability or price of oil and natural gas or other forms of energy, as well as business conditions, conservation, legislation, regulations and the ability to convert to alternate fuels and other forms of energy may affect the demand for oil and natural gas.

Transportation

During the initial development of Arabella’s fields, Arabella considers all gathering and delivery infrastructure in the areas of Arabella’s production. Arabella’s oil is transported from the wellhead to Arabella’s tank batteries by Arabella’s gathering systems. The oil is then transported by the purchaser by truck to a tank farm where it is further transported by pipeline. Arabella’s natural gas is generally transported from the wellhead to the purchaser’s pipeline interconnection point through Arabella’s gathering system.

Oil and Natural Gas Leases

The typical oil and natural gas lease agreement covering Arabella’s properties provides for the payment of royalties to the mineral owner for all oil and natural gas produced from any wells drilled on the leased premises. The lessor royalties and other leasehold burdens on Arabella’s properties are currently 25.00%, resulting in a net revenue to working interest owners of 75.00%.

Seasonal Nature of Business

Generally, demand for oil and natural gas decreases during the summer months and increases during the winter months. Certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer, which can lessen seasonal demand fluctuations. Seasonal weather conditions and lease stipulations can limit Arabella’s drilling and producing activities and other oil and natural gas operations in a portion of Arabella’s operating areas. These seasonal anomalies can pose challenges for meeting Arabella’s well drilling objectives and can increase competition for equipment, supplies and personnel during the spring and summer months, which could lead to shortages and increase costs or delay operations.

Regulation

Oil and natural gas operations such as ours are subject to various types of legislation, regulation and other legal requirements enacted by governmental authorities. This legislation and regulation affecting the oil and natural gas industry is under constant review for amendment or expansion. Some of these requirements carry substantial penalties for failure to comply. The regulatory burden on the oil and natural gas industry increases Arabella’s cost of doing business and, consequently, affects Arabella’s profitability.

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Environmental Matters and Regulation

Arabella’s oil and natural gas exploration, development and production operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Numerous governmental agencies, such as the U.S. Environmental Protection Agency, or the EPA, issue regulations which often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties and may result in injunctive obligations for non-compliance. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically sensitive and other protected areas, require action to prevent or remediate pollution from current or former operations, such as plugging abandoned wells or closing pits, result in the suspension or revocation of necessary permits, licenses and authorizations, require that additional pollution controls be installed and impose substantial liabilities for pollution resulting from Arabella’s operations or relate to Arabella’s owned or operated facilities. The strict and joint and several liability nature of such laws and regulations could impose liability upon Arabella regardless of fault. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly pollution control or waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect Arabella’s operations and financial position, as well as the oil and natural gas industry in general. Arabella’s management believes that Arabella is in substantial compliance with applicable environmental laws and regulations and Arabella has not experienced any material adverse effect from compliance with these environmental requirements. This trend, however, may not continue in the future.

Waste Handling

The Resource Conservation and Recovery Act, as amended, or RCRA, and comparable state statutes and regulations promulgated thereunder, affect oil and natural gas exploration, development and production activities by imposing requirements regarding the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. With federal approval, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Although most wastes associated with the exploration, development and production of crude oil and natural gas are exempt from regulation as hazardous wastes under RCRA, such wastes may constitute “solid wastes” that are subject to the less stringent requirements of nonhazardous waste provisions. However, Arabella cannot assure you that the EPA or state or local governments will not adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous for future regulation. Indeed, legislation has been proposed from time to time in Congress to re-categorize certain oil and natural gas exploration, development and production wastes as “hazardous wastes.” Any such changes in the laws and regulations could have a material adverse effect on Arabella’s capital expenditures and operating expenses.

Administrative, civil and criminal penalties can be imposed for failure to comply with waste handling requirements. Arabella believes that Arabella is in substantial compliance with applicable requirements related to waste handling, and that Arabella hold all necessary and up-to-date permits, registrations and other authorizations to the extent that Arabella’s operations require them under such laws and regulations. Although Arabella does not believe the current costs of managing Arabella’s wastes, as presently classified, to be significant, any legislative or regulatory reclassification of oil and natural gas exploration and production wastes could increase Arabella’s costs to manage and dispose of such wastes.

Remediation of Hazardous Substances

The Comprehensive Environmental Response, Compensation and Liability Act, as amended, also known as CERCLA or the “Superfund” law, and analogous state laws, generally imposes strict and joint and several liability, without regard to fault or legality of the original conduct, on classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the current owner or operator of a contaminated facility, a former owner or operator of the facility at the time of contamination, and those persons that disposed or arranged for the disposal of the hazardous substance at the facility. Under CERCLA and comparable state statutes, persons deemed “responsible parties” may be subject to strict and joint and several liability for the costs of removing or remediating previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination), for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. In the course of Arabella’s operations, Arabella use materials that, if released, would be subject to CERCLA and comparable state statutes. Therefore, governmental agencies or third parties may seek to hold Arabella responsible under CERCLA and comparable state statutes for all or part of the costs to clean up sites at which such “hazardous substances” have been released.

Water Discharges

The Federal Water Pollution Control Act of 1972, as amended, also known as the “Clean Water Act,” the Safe Drinking Water Act, the Oil Pollution Act, or OPA, and analogous state laws and regulations promulgated thereunder impose restrictions and strict controls regarding the unauthorized discharge of pollutants, including produced waters and other gas and oil wastes, into navigable waters of the United States, as well as state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. The Clean Water Act and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit. Spill prevention, control and countermeasure plan requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. These laws and regulations also prohibit certain activity in wetlands unless authorized by a permit issued by the U.S. Army Corps of Engineers. The EPA has also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain individual permits or coverage under general permits for storm water discharges. In addition, on October 20, 2011, the EPA announced a schedule to develop pre-treatment standards for wastewater discharges produced by natural gas extraction from underground coalbed and shale formations. The EPA stated that it will gather data, consult with stakeholders, including ongoing consultation with industry, and solicit public comment on a proposed rule for shale gas in 2014. Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans, as well as for monitoring and sampling the storm water runoff from certain of Arabella’s facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions.

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The Oil Pollution Act is the primary federal law for oil spill liability. The OPA contains numerous requirements relating to the prevention of and response to petroleum releases into waters of the United States, including the requirement that operators of offshore facilities and certain onshore facilities near or crossing waterways must develop and maintain facility response contingency plans and maintain certain significant levels of financial assurance to cover potential environmental cleanup and restoration costs. The OPA subjects owners of facilities to strict, joint and several liability for all containment and cleanup costs and certain other damages arising from a release, including, but not limited to, the costs of responding to a release of oil to surface waters.

Noncompliance with the Clean Water Act or OPA may result in substantial administrative, civil and criminal penalties, as well as injunctive obligations. Arabella believes Arabella is in material compliance with the requirements of each of these laws.

Air Emissions

The Federal Clean Air Act, as amended, and comparable state laws and regulations, regulate emissions of various air pollutants through the issuance of permits and the imposition of other requirements. The EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants at specified sources. New facilities may be required to obtain permits before work can begin, and existing facilities may be required to obtain additional permits and incur capital costs in order to remain in compliance. For example, on April 17, 2012, the EPA approved final regulations under the federal Clean Air Act that establish new emission controls for oil and natural gas production and processing operations, which regulations are discussed in more detail below in “Regulation of Hydraulic Fracturing.” These laws and regulations may increase the costs of compliance for some facilities Arabella own or operate, and federal and state regulatory agencies can impose administrative, civil and criminal penalties for noncompliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations. Arabella believes that Arabella is in substantial compliance with all applicable air emissions regulations and that Arabella hold all necessary and valid construction and operating permits for Arabella’s operations. Obtaining or renewing permits has the potential to delay the development of oil and natural gas projects.

Climate Change

Many nations have agreed to limit emissions of “greenhouse gases” pursuant to the United Nations Framework Convention on Climate Change, also known as the “Kyoto Protocol.” Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of oil, natural gas and refined petroleum products, are “greenhouse gases,” or GHGs, regulated by the Kyoto Protocol. Although the United States is not participating in the Kyoto Protocol at this time, several states or geographic regions have adopted legislation and regulations to reduce emissions of GHGs. Additionally, on April 2, 2007, the U.S. Supreme Court ruled, in Massachusetts, et al. v. EPA , that the EPA has the authority to regulate the emission of carbon dioxide from automobiles as an “air pollutant” under the federal Clean Air Act. Thereafter, in December 2009, the EPA issued an Endangerment Finding that determined that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment because, according to the EPA, emissions of such gases contribute to warming of the earth’s atmosphere and other climatic changes. These findings by the EPA allowed the agency to proceed with the adoption and implementation of regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act. Subsequently, the EPA adopted two sets of related rules, one of which purports to regulate emissions of GHGs from motor vehicles and the other of which regulates emissions of GHGs from certain large stationary sources of emissions such as power plants or industrial facilities. The EPA finalized the motor vehicle rule, which purports to limit emissions of GHGs from motor vehicles manufactured in model years 2012-2016, in April 2010 and it became effective in January 2011, although it does not require immediate reductions in GHG emissions. A recent rulemaking proposal by the EPA and the Department of Transportation’s National Highway Traffic Safety Administration seeks to expand the motor vehicle rule to include 16 vehicles manufactured in model years 2017-2025. The EPA adopted the stationary source rule, also known as the “Tailoring Rule,” in May 2010, and it also became effective in January 2011, although it remains subject of several pending lawsuits filed by industry groups. The Tailoring Rule establishes new GHG emissions thresholds that determine when stationary sources must obtain permits under the Prevention of Significant Deterioration, or PSD, and Title V programs of the Clean Air Act. The permitting requirements of the PSD program apply only to newly constructed or modified major sources. Obtaining a PSD permit requires a source to install best available control technology, or BACT, for those regulated pollutants that are emitted in certain quantities. Phase I of the Tailoring Rule, which became effective on January 2, 2011, requires projects already triggering PSD permitting that are also increasing GHG emissions by more than 75,000 tons per year to comply with BACT rules for their GHG emissions. Phase II of the Tailoring Rule, which became effective on July 1, 2011, requires preconstruction permits using BACT for new projects that emit 100,000 tons of GHG emissions per year or existing facilities that make major modifications increasing GHG emissions by more than 75,000 tons per year. Phase III of the Tailoring Rule, which is expected to go into effect in 2013, will seek to streamline the permitting process and permanently exclude smaller sources from the permitting process. Additionally, in September 2009, the EPA issued a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the U.S., including natural gas liquids fractionators and local natural gas/distribution companies, beginning in 2011 for emissions occurring in 2010. In November 2010, the EPA expanded its existing GHG reporting rule to include onshore and offshore oil and natural gas production and onshore processing, transmission, storage and distribution facilities, which may include certain of Arabella’s facilities, beginning in 2012 for emissions occurring in 2011. The EPA is also under a legal obligation pursuant to a consent decree with certain environmental groups to issue new source performance standards for refineries. The EPA has also adopted regulations imposing best available control technology requirements on the largest greenhouse gas stationary sources, regulations requiring reporting of greenhouse gas emissions from certain facilities, and it is considering additional regulation of greenhouse gases as “air pollutants.” As a result of this continued regulatory focus, future GHG regulations of the oil and gas industry remain a possibility.

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In addition, the U.S. Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Although the U.S. Congress has not adopted such legislation at this time, it may do so in the future and many states continue to pursue regulations to reduce greenhouse gas emissions. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances that correspond to their annual emissions of GHGs. The number of allowances available for purchase is reduced each year until the overall GHG emission reduction goal is achieved. As the number of GHG emission allowances declines each year, the cost or value of such allowances is expected to escalate significantly.

Regulation of Hydraulic Fracturing

Hydraulic fracturing is an important common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations, including shales. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The federal Safe Drinking Water Act, or SDWA, regulates the underground injection of substances through the Underground Injection Control, or UIC, program. Hydraulic fracturing generally is exempt from regulation under the UIC program, and the hydraulic fracturing process is typically regulated by state oil and gas commissions. The EPA, however, has recently taken the position that hydraulic fracturing with fluids containing diesel fuel is subject to regulation under the UIC program, specifically as “Class II” UIC wells. At the same time, the White House Council on Environmental Quality is coordinating an administration–wide review of hydraulic fracturing practices and the EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities. Moreover, the EPA announced on October 20, 2011 that it is also launching a study regarding wastewater resulting from hydraulic fracturing activities and currently plans to propose standards by 2014 that such wastewater must meet before being transported to a treatment plant. As part of these studies, the EPA has requested that certain companies provide them with information concerning the chemicals used in the hydraulic fracturing process. These studies, depending on their results, could spur initiatives to regulate hydraulic fracturing under the SDWA or otherwise.

Legislation to amend the SDWA to repeal the exemption for hydraulic fracturing from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, were proposed in recent sessions of Congress. The U.S. Congress continues to consider legislation to amend the SDWA.

On April 17, 2012, the EPA approved final regulations under the federal Clean Air Act that establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA’s rule package includes New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds, or VOCs, and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The final rule seeks to achieve a 95% reduction in VOCs emitted by requiring the use of reduced emission completions or “green completions” on all hydraulically-fractured wells constructed or refractured after January 1, 2015. The rules also establish specific new requirements regarding emissions from compressors, controllers, dehydrators, storage tanks and other production equipment. These rules will require a number of modifications to Arabella’s operations, including the installation of new equipment to control emissions from Arabella’s wells by January 1, 2015. Compliance with such rules could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact Arabella’s business.

In addition, there are certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The federal government is currently undertaking several studies of hydraulic fracturing’s potential impacts, the results of which are expected in 2014. These ongoing or proposed studies, depending on their degree of pursuit and whether any meaningful results are obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory authorities. The U.S. Department of Energy is conducting an investigation into practices the agency could recommend to better protect the environment from drilling using hydraulic-fracturing completion methods. Additionally, certain members of Congress have called upon the U.S. Government Accountability Office to investigate how hydraulic fracturing might adversely affect water resources, the SEC to investigate the natural-gas industry and any possible misleading of investors or the public regarding the economic feasibility of pursuing natural gas deposits in shale formations by means of hydraulic fracturing, and the U.S. Energy Information Administration to provide a better understanding of that agency’s estimates regarding natural gas reserves, including reserves from shale formations, as well as uncertainties associated with those estimates.

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Several states, including Texas, and the Department of the Interior, in a May 4, 2012 proposed rule covering federal lands, have adopted, or are considering adopting, regulations that could restrict or prohibit hydraulic fracturing in certain circumstances and/or require the disclosure of the composition of hydraulic fracturing fluids. On May 31, 2011, the Texas Legislature adopted new legislation requiring oil and gas operators to publicly disclose the chemicals used in the hydraulic fracturing process. It was signed into law on June 17, 2011, effective as of September 1, 2011. The Texas Railroad Commission has adopted rules and regulations implementing this legislation that will apply to all wells for which the Railroad Commission issues an initial drilling permit on or after February 1, 2012. The new law requires that the well operator disclose the list of chemical ingredients subject to the requirements of the federal Occupational Safety and Health Act (OSHA) for disclosure on an internet website and also file the list of chemicals with the Texas Railroad Commission with the well completion report. The total volume of water used to hydraulically fracture a well must also be disclosed to the public and filed with the Texas Railroad Commission.

There has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, impacts on drinking water supplies, use of water and the potential for impacts to surface water, groundwater and the environment generally. A number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic fracturing practices. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for Arabella to perform fracturing to stimulate production from tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, if hydraulic fracturing is further regulated at the federal or state level, Arabella’s fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. Such legislative changes could cause Arabella to incur substantial compliance costs, and compliance or the consequences of any failure to comply by Arabella could have a material adverse effect on Arabella’s financial condition and results of operations. At this time, it is not possible to estimate the impact on Arabella’s business of newly enacted or potential federal or state legislation governing hydraulic fracturing.

Other Regulation of the Oil and Natural Gas Industry

The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations that are binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases Arabella’s cost of doing business and, consequently, affects Arabella’s profitability, these burdens generally do not affect Arabella any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.

The availability, terms and cost of transportation significantly affect sales of oil and natural gas. The interstate transportation and sale for resale of oil and natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission, or FERC. Federal and state regulations govern the price and terms for access to oil and natural gas pipeline transportation. FERC’s regulations for interstate oil and natural gas transmission in some circumstances may also affect the intrastate transportation of oil and natural gas.

Although oil and natural gas prices are currently unregulated, Congress historically has been active in the area of oil and natural gas regulation. Arabella cannot predict whether new legislation to regulate oil and natural gas might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on Arabella’s operations. Sales of condensate and oil and natural gas liquids are not currently regulated and are made at market prices.

Drilling and Production

Arabella’s operations are subject to various types of regulation at the federal, state and local level. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. The state, and some counties and municipalities, in which Arabella operates also regulate one or more of the following:

● the location of wells;

● the method of drilling and casing wells;

● the timing of construction or drilling activities, including seasonal wildlife closures;

● the rates of production or “allowables”;

● the surface use and restoration of properties upon which wells are drilled;

● the plugging and abandoning of wells; and

● notice to, and consultation with, surface owners and other third parties.

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State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce Arabella’s interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas Arabella can produce from Arabella’s wells or limit the number of wells or the locations at which Arabella can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction. States do not regulate wellhead prices or engage in other similar direct regulation, but Arabella cannot assure you that they will not do so in the future. The effect of such future regulations may be to limit the amounts of oil and natural gas that may be produced from Arabella’s wells, negatively affect the economics of production from these wells or to limit the number of locations Arabella can drill.

Federal, state and local regulations provide detailed requirements for the abandonment of wells, closure or decommissioning of production facilities and pipelines and for site restoration in areas where Arabella operates. The U.S. Army Corps of Engineers and many other state and local authorities also have regulations for plugging and abandonment, decommissioning and site restoration. Although the U.S. Army Corps of Engineers does not require bonds or other financial assurances, some state agencies and municipalities do have such requirements.

Natural Gas Sales and Transportation

Historically, federal legislation and regulatory controls have affected the price of the natural gas Arabella produce and the manner in which Arabella market Arabella’s production. FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. Since 1978, various federal laws have been enacted which have resulted in the complete removal of all price and non-price controls for sales of domestic natural gas sold in “first sales,” which include all of Arabella’s sales of Arabella’s own production. Under the Energy Policy Act of 2005, FERC has substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties.

FERC also regulates interstate natural gas transportation rates and service conditions and establishes the terms under which Arabella may use interstate natural gas pipeline capacity, which affects the marketing of natural gas that Arabella produce, as well as the revenues Arabella receive for sales of Arabella’s natural gas and release of Arabella’s natural gas pipeline capacity. Commencing in 1985, FERC promulgated a series of orders, regulations and rule makings that significantly fostered competition in the business of transporting and marketing gas. Today, interstate pipeline companies are required to provide nondiscriminatory transportation services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. FERC’s initiatives have led to the development of a competitive, open access market for natural gas purchases and sales that permits all purchasers of natural gas to buy gas directly from third-party sellers other than pipelines. However, the natural gas industry historically has been very heavily regulated; therefore, Arabella cannot guarantee that the less stringent regulatory approach currently pursued by FERC and Congress will continue indefinitely into the future nor can Arabella determine what effect, if any, future regulatory changes might have on Arabella’s natural gas related activities.

Under FERC’s current regulatory regime, transmission services must be provided on an open-access, nondiscriminatory basis at cost-based rates or at market-based rates if the transportation market at issue is sufficiently competitive. Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in state waters. Although its policy is still in flux, FERC has in the past reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the tendency to increase Arabella’s costs of transporting gas to point-of-sale locations.

Oil Sales and Transportation

Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future.

Arabella’s crude oil sales are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is also subject to rate regulation. FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act and intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, Arabella believes that the regulation of oil transportation rates will not affect Arabella’s operations in any materially different way than such regulation will affect the operations of Arabella’s competitors.

Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by portioning provisions set forth in the pipelines’ published tariffs. Accordingly, Arabella believes that access to oil pipeline transportation services generally will be available to Arabella to the same extent as to Arabella’s competitors.

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State Regulation

Texas regulates the drilling for, and the production, gathering and sale of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. Texas currently imposes a 4.6% severance tax on oil production and a 7.5% severance tax on natural gas production. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and natural gas resources. States may regulate rates of production and may establish maximum daily production allowables from 20 oil and natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but Arabella cannot assure you that they will not do so in the future. The effect of these regulations may be to limit the amount of oil and natural gas that may be produced from Arabella’s wells and to limit the number of wells or locations Arabella can drill.

The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to resource conservation and equal employment opportunity. Arabella does not believe that compliance with these laws will have a material adverse effect on Arabella.

Operational Hazards and Insurance

The oil business involves a variety of operating risks, including the risk of fire, explosions, blow outs, pipe failures and, in some cases, abnormally high pressure formations which could lead to environmental hazards such as oil spills, natural gas leaks and the discharge of toxic gases. If any of these should occur, Arabella could incur legal defense costs and could be required to pay amounts due to injury, loss of life, damage or destruction to property, natural resources and equipment, pollution or environmental damage, regulatory investigation and penalties and suspension of operations.

In accordance with what Arabella believes to be industry practice, Arabella maintain insurance against some, but not all, of the operating risks to which Arabella’s business is exposed. Arabella currently have insurance policies for onshore property (oil lease property/production equipment) for selected locations, rig physical damage protection, control of well protection for selected wells, comprehensive general liability, commercial automobile, workers compensation, pollution liability (claims made coverage with a policy retroactive date), excess umbrella liability and other coverage.

Arabella’s insurance is subject to exclusion and limitations, and there is no assurance that such coverage will fully or adequately protect Arabella against liability from all potential consequences, damages and losses. Any of these operational hazards could cause a significant disruption to Arabella’s business. A loss not fully covered by insurance could have a material adverse effect on Arabella’s financial position, results of operations and cash flows. See “Item 1A. Risk Factors–Risks Related to the Oil and Natural Gas Industry and Arabella’s Business–Operating hazards and uninsured risks may result in substantial losses and could prevent Arabella from realizing profits.”

Arabella reevaluates the purchase of insurance, policy terms and limits annually. Future insurance coverage for Arabella’s industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that Arabella believes are economically acceptable. No assurance can be given that Arabella will be able to maintain insurance in the future at rates that Arabella consider reasonable and Arabella may elect to maintain minimal or no insurance coverage. Arabella may not be able to secure additional insurance or bonding that might be required by new governmental regulations. This may cause Arabella to restrict Arabella’s operations, which might severely impact Arabella’s financial position. The occurrence of a significant event, not fully insured against, could have a material adverse effect on Arabella’s financial condition and results of operations.

Generally, Arabella also require Arabella’s third party vendors to sign master service agreements in which they agree to indemnify Arabella for injuries and deaths of the service provider’s employees as well as contractors and subcontractors hired by the service provider.

C.      Organizational Structure

We were organized under the laws of the Cayman Islands on June 17, 2010 as an exempted company with limited liability.  Arabella LLC is a Texas limited liability company and is wholly owned by us. Neither Arabella LLC nor we own interests in any other entities.

D.      Property, Plant and Equipment

We maintain our principal executive offices at 500 W. Texas Avenue, Suite 1450, Midland, Texas 79701. We believe that our facilities are adequate for our current operations.

ITEM 4A. UNRESOLVED STAFF COMMENTS

None.

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ITEM 5. OPERATING AND FINANCIAL REVIEW AND PROSPECTS

You should read the following discussion and analysis of our financial condition and results of operations in conjunction with the section titled “Selected Financial Data” and the consolidated financial statements included elsewhere in this report. This discussion and analysis may contain forward-looking statements based upon current expectations that involve risks and uncertainties. Our actual results may differ materially from those anticipated in these forward-looking statements as a result of various factors, including those set forth in “Risk Factors” of this report.

Overview

Arabella is an independent oil and natural gas company focused on the acquisition, development, exploration and exploitation of unconventional, long-life, onshore oil and natural gas reserves in the Delaware Basin in West Texas, which a part of the Permian Basin. Arabella’s activities are primarily directed at the Avalon, Bone Springs, and Wolfcamp formations which Arabella refer to as the Wolfbone play. Arabella intends to grow Arabella’s reserves and production through development drilling, exploitation and exploration activities on Arabella’s multi-year inventory of identified potential drilling locations and through acquisitions that meet Arabella’s strategic and financial objectives, targeting oil-weighted reserves. Substantially all of Arabella’s revenues are generated through the sale of oil, natural gas liquids and natural gas production. Arabella’s production was approximately 95% oil, no natural gas liquids and 5% natural gas for the year ended December 31, 2013, and was approximately 85% oil, no natural gas liquids and 15% natural gas for the year ended December 31, 2012. In 2011, Arabella’s production was insignificant. On December 31, 2013, Arabella’s net acreage position in the Delaware Basin was approximately 5,037 net acres. On December 31, 2012, Arabella’s net acreage position in the Delaware Basin was approximately 1,601 net acres.

Operating Results Overview

During the year ended December 31, 2013, Arabella’s average daily production was approximately 43 BOE, consisting of 38 Bbls/d of oil, 30 Mcf/d of natural gas and no natural gas liquids, this is a significant increase for the years ending December 31, 2012 and 2011, wherein there was virtually no production.

During the year ended December 31, 2013, Arabella participated in 5 gross (1.25 net) non-operated wells in the Delaware Basin.

Reserves and pricing

In the table below, WPC estimated all of Arabella’s proved reserves at December 31, 2013 and December 31, 2012. The prices used to estimate proved reserves for all periods were held constant throughout the life of the properties and have been adjusted for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead.

	December 31, 2013		December 31, 2012
Estimated Net Proved Reserves:
Oil (MBbls)		1,540.4		166.3
Natural gas (MMcf)		3,197.3		377.2
Total (MBOE)		2,073.3		229.2

	December 31, 2013			December 31, 2012
	Unweighted Arithmetic Average First-Day-of-the-Month Prices
Oil (Bbls)		$	91.24		$	89.14
Natural gas (Mcf)			6.06			7.23

Sources of Arabella’s revenue

Arabella’s revenues are derived from the sale of oil and natural gas production, as well as the sale of natural gas liquids that are extracted from Arabella’s natural gas during processing. For the years ended December 31, 2013 and December 31, 2012, Arabella’s revenues were derived 95% and 85%, respectively, from oil sales, 0% and 0%, respectively, from natural gas liquids sales and 5% and 15%, respectively, from natural gas sales. Arabella’s revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices. Oil, natural gas liquids and natural gas prices have historically been volatile. During 2013, West Texas Intermediate posted prices ranged from $86.65 to $110.62 per Bbl and the Henry Hub spot market price of natural gas ranged from $3.08 to $4.52 per MMBtu. On December 31, 2013, the West Texas Intermediate posted price for crude oil was $98.17 per Bbl and the Henry Hub spot market price of natural gas was $4.31 per MMBtu.

During the years ended December 31, 2012 and December 31, 2011, Arabella had other revenue from the gain on sale of oil and gas properties. Though it may occur from time to time, Arabella does not expect gains or losses on sales of oil and gas properties to be a regular portion of Arabella’s business on an ongoing basis.

Principal components of Arabella’s cost structure

Lease operating expenses. These are daily costs incurred to bring oil and natural gas out of the ground and to the market, together with the daily costs incurred to maintain Arabella’s producing properties. Such costs also include maintenance, repairs and workover expenses related to Arabella’s oil and natural gas properties.

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Ad valorem and production taxes. Production taxes are paid on produced oil and natural gas based on a percentage of revenues from products sold at fixed rates established by federal, state or local taxing authorities. Arabella is also subject to ad valorem taxes in the counties where Arabella’s production is located. Ad valorem taxes are generally based on the valuation of Arabella’s oil and gas properties.

Depreciation, depletion and amortization. Arabella follows the successful efforts method for oil and gas properties, whereby costs of productive wells, developmental dry holes and productive leases are capitalized into appropriate groups of properties based on geographical and geological similarities. These capitalized costs are amortized on a field by filed basis using the unit-of-production method based on estimated proved reserves. Additionally, gain or loss is generally recognized on all sales of natural gas and oil properties under the successful efforts method.

Exploration expense. Exploration costs, including geological and geophysical expenses and delay rentals, are charged to expense as incurred. Exploratory drilling costs, including the cost of stratigraphic test wells, are initially capitalized but charged to exploration expense if and when the well is determined to be nonproductive. The determination of an exploratory well’s ability to produce must be made within one year from the completion of drilling activities. The acquisition costs of unproved acreage are initially capitalized and are carried at cost, net of accumulated impairment provisions, until such leases are transferred to proved properties or charged to exploration expense as impairments of unproved properties.

General and administrative. These are costs incurred for overhead, including payroll and benefits for Arabella’s corporate staff, costs of maintaining Arabella’s headquarters, costs of managing Arabella’s production and development operations, franchise taxes, audit and other fees for professional services and legal compliance.

General and administrative expenses allocated from Arabella Petroleum Company. These are general and administrative costs that were subject to a cost sharing agreement with Arabella Petroleum Company, which is owned and controlled by Jason Hoisager. These include a portion of the rent for office space, office equipment and administrative services.

Results of Operations

The following table sets forth selected historical operating data for the periods indicated.

	December 31, 2013		December 31, 2012		December 31, 2011
Revenues:
Oil and gas revenue	$	1,421,915	$	65,881	$	16,543
Other operating revenue – gain on sale of oil and gas properties		--		402,901		34,467
Total revenues		1,421,915		468,782		51,010
Costs and expenses:
Lease operating expenses		152,052		12,526		5,753
Ad valorem and production taxes		64,033		3,174		819
Depreciation, depletion and amortization		469,230		27,696		5,724
Accretion of asset retirement obligation		663		215		97
General and administrative expenses		412,268		10,010		10,011
General and administrative expenses allocated from Arabella Petroleum Company		131,950		93,845		30,071
Total costs and expenses		1,230,196		147,466		52,475
Net income (loss)	$	191,719	$	321,316		(1,465	)

	December 31, 2013		December 31, 2012		December 31, 2011
Production Data:
Oil (Bbls)		13,915		678		145
Natural gas (Mcf)		11,048		1,338		392
Combined volumes (BOE)		15,756		901		210
Daily combined volumes (BOE/d)		43.2		2.5		0.6
Average Prices(1):
Oil (per Bbl)	$	96.45	$	86.78	$	89.56
Natural gas (per Mcf)		6.88		5.26		9.07
Combined (per BOE)		90.01		73.11		78.77
Average Costs (per BOE):
Lease operating expense	$	9.65	$	13.90	$	27.25
Production Taxes		4.06		3.52		3.90
Production Taxes as a % of sales		4.5		4.8		4.9
Depreciation, depletion and amortization		29.78		41.80		33.50
General and Administrative		34.54		142.50		79.10

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Comparison of Years ended December 31, 2013 and December 31, 2012

Oil and Natural Gas Revenues. Arabella’s oil and natural gas revenues increased by $1,356,034, or 2,058%, to $1,421,915 for the year ended December 31, 2013, as compared to $65,881 for the year ended December 31, 2012. Arabella’s revenues are a function of oil and natural gas production volumes sold and average sales prices received for those volumes. The reason for the increase in revenues is due to increased sales of oil and natural gas due to the completion of wells in the second half of 2013. In the second half of 2013, the Topo Chico #4, Graham #1H, Locker State #1H and the Woods #1H began production. Production from these wells combined with relatively consistent prices for oil and natural gas and the fact that Arabella did not have meaningful production until the second quarter of 2013 accounted for the increase in revenue.

Other Operating Revenue. Other operating revenue in 2012 relates to oil and gas property sales. In 2012, a major field in which Arabella held an interest was sold and substantially all of the $402,901 other income relates to the gain on that sale. Arabella had a small property sale during 2011 which provided a gain of $34,467. Other operating revenue from the sale of oil and gas properties fluctuates due to market demand and preparation of the land. Arabella does not expect property sales to be a focus of Arabella’s business on a continuing basis.

Lease Operating Expense. Lease operating expenses increased from $12,526 in 2012 to $152,052 in 2013. This increase is the direct result of new wells that were completed in second half of 2013 as described under revenues, above. Lease operating expenses can vary based upon conditions at the well site and well productivity and Arabella’s experience in operating the newly completed producing wells in 2013 was better than in 2012.

Ad Valorem and Production Tax Expense. Ad valorem and production taxes as a percentage of oil and natural gas revenues improved slightly for 2013 and 2012. There was an overall increase in taxes due to the revenue increase discussed above. Ad valorem and production taxes are primarily based on the market value of Arabella’s production at the wellhead and may vary across the different counties in which Arabella operates.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense increased from $27,696 in 2012 to $469,230 in 2013. The increase is related to increased production from the new wells discussed under revenue, above.

General and Administrative. General and administrative expenses increased from $10,010 in 2012 to $412,268 in 2013. These expenses relate primarily to salaries and wages, legal fees and professional fees.  The increase is related to additional general and administrative costs relating to increased drilling and production activity in 2013.

General and Administrative expenses allocated from Arabella Petroleum Company. General and administrative expense allocated from Arabella Petroleum Company, which is owned and controlled by Jason Hoisager, increased to $131,950 in 2013 from $93,845 in 2012. These fees are based upon a cost sharing arrangement with Arabella Petroleum Company and the increase was expected with greater drilling activity in 2013 compared to 2012.

Comparison of Years ended December 31, 2012 and December 31, 2011

Oil and Natural Gas Revenues. Arabella’s oil, natural gas liquids and natural gas revenues increased by $49,338, or 298%, to $65,881 for the year ended December 31, 2012, as compared to $16,543 for the year ended December 31, 2011. Arabella’s revenues are a function of oil and natural gas production volumes sold and average sales prices received for those volumes. The reason for the increase in revenues is due to increased sales of oil, natural gas liquids and natural gas due to the completion of wells in the second half of 2012. In the second half of 2012, the SM Prewitt #1H and the Topo Chico #1 began production. Production from these wells combined with a relatively consistent prices for oil and natural gas and the fact that Arabella did not have meaningful production until the second quarter of 2012 accounted for the increase in revenue.

Other Operating Revenue. Other operating revenue in 2012 and 2011 relates to oil and gas property sales. In 2012, a major field in which Arabella held an interest was sold and substantially all of the $402,901 other revenue relates to the gain on that sale. Arabella had a small property sale during 2011 which provided a gain of $34,467. Other operating revenue from the sale of oil and gas properties fluctuates due to market demand and preparation of the land. Arabella does not expect property sales to be a focus of Arabella’s business on a continuing basis.

Lease Operating Expense. Lease operating expenses increased from $5,753 in 2011 to $12,526 in 2012. This increase is the direct result of new wells that were completed in second half of 2012 as described under revenues, above. Lease operating expenses can vary based upon conditions at the well site and well productivity and Arabella’s experience in operating the newly completed producing wells in 2012 was better than in 2011.

Ad Valorem and Production Tax Expense. Ad valorem and production taxes as a percentage of oil and natural gas revenues were consistent for 2012 and 2011. There was an overall increase in taxes due to the revenue increase discussed above. Ad valorem and production taxes are primarily based on the market value of Arabella’s production at the wellhead and may vary across the different counties in which Arabella operates.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense increased from $5,724 in 2011 to $27,696 in 2012. The increase is related to increased production from the new wells discussed under revenue, above.

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General and Administrative. General and administrative expenses were consistent from 2011 to 2012. These expenses relate primarily to outside accounting fees.

General and Administrative expenses allocated from Arabella Petroleum Company. General and administrative expense allocated from Arabella Petroleum Company, which is owned and controlled by Jason Hoisager, increased to $93,845 in 2012 from $30,071 in 2011. These fees are based upon a cost sharing arrangement with Arabella Petroleum Company and the increase was expected with greater drilling activity in 2012 compared to 2011.

Liquidity and Capital Resources

Arabella’s primary source of liquidity has been a substantial increase in oil and gas sales revenue and the sales of certain properties as well as equity contributions from the Acquisition and equity and loans from Arabella’s founder Jason Hoisager. Arabella’s primary uses of capital have been the acquisition, development and exploration of oil and natural gas properties. As Arabella pursues reserves and production growth, Arabella regularly considers which capital resources, including equity and debt financings, are available to meet Arabella’s future financial obligations, planned capital expenditure activities and liquidity requirements. Arabella’s future ability to grow proved reserves and production will be highly dependent on the capital resources available to Arabella.

Liquidity and cash flow

Arabella had a working capital deficit of $1,240,656 as of December 31, 2013. Arabella’s net cash flow for the year ended December 31, 2013 was an increase of $2,105,543, the components of which are described below. Arabella’s cash flow for the years ended December 31, 2012 and December 31, 2011 were increases of $12,975 and $15, respectively.

Arabella commenced its oil and gas exploration activities in 2011. During the year ended December 31, 2013, the Company’s oil and gas properties increased $12.2 million in costs. In addition, the Company had negative working capital of $1,240,656 at December 31, 2013, and has not raised additional debt or equity to drill additional wells and support higher costs and expenses in 2014. These conditions raise substantial doubt about the Company’s ability to continue as a going concern. Arabella’s ability to continue as a going concern is dependent on its ability to develop its oil and gas properties and achieve profitable operations and to generate sufficient cash flow from financing and operations to meet its obligations as they become payable. Arabella expects that it will need approximately $40 million to fund its operations during the next twelve months, which will include minimum annual property lease payments, well expenditures and operating costs and expenses.  Arabella has plans to seek additional capital through private debt for the development of its oil and gas properties and operating costs and expenses. Although there are no assurances that management’s plans will be realized, Arabella believes that it will be able to continue operations in the future.

Operating Activities

Net cash provided by operating activities was $380,934 for the year ended December 31, 2013, as compared to $88,536 for the year ended December 31, 2012. The increase in operating cash flows is largely a result of an increase in the noncash expenses such as depreciation, depletion and amortization and allocated general and administrative expenses offset by an increase in accounts receivable which increased $441,534 and $38,105, respectively, from the 2012 period to the 2013 period.

Net cash provided by operating activities was $88,536 for the year ended December 31, 2012, as compared to $6,245 for the year ended December 31, 2011. The increase in operating cash flows is primarily due to an increase of $63,774 relating to the contribution of the sole member for general and administrative expenses from Arabella Petroleum Company, which is owned and controlled by Jason Hoisager.  Net cash provided by operating activities was reduced by $402,901 and $34,467 in 2012 and 2011, respectively, by gains related to sales of oil and gas properties.

Arabella’s operating cash flow is sensitive to many variables, the most significant of which is the volatility of prices for the oil and natural gas Arabella produces. Prices for these commodities are determined primarily by prevailing market conditions. Regional and worldwide economic activity, weather and other substantially variable factors influence market conditions for these products. These factors are beyond Arabella’s control and are difficult to predict.

Investing Activities

The purchase and development of oil and natural gas properties accounted for the majority of Arabella’s cash outlays for investing activities. During the year ended December 31, 2013, the sole member, Jason Hoisager, transferred a carrying value of $6,014,340 in oil and gas properties from Arabella Petroleum Company, in exchange for a $3,007,170 non-interest bearing, unsecured loan to Jason Hoisager and an equity contribution in the amount of $3,007,170.

Arabella used net cash for investing activities of $3,498,808, $89,117 and $98,422 for the years ended December 31, 2013, December 31, 2012 and December 31, 2011, respectively. During the years ended December 31, 2012 and December 31, 2011, Arabella received proceeds of $592,702 and $34,667 from sales of oil and gas properties, respectively. Arabella used cash for investing in oil and natural gas properties in the amounts of $3,718,303, $526,642 and $68,771, respectively.  In 2013, Arabella used $219,495 in prepaid drilling costs against actual drilling costs and in 2012 and 2011 Arabella used cash in the amounts of $155,177 and $64,318, respectively to prepay drilling costs.

Financing Activities

During 2013, Arabella received $5,183,417 of cash related to the Acquisition.  During the years ended December 31, 2012 and December 31, 2011, Arabella received net amounts of $13,556 and $92,192, respectively, in shareholder loans.

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Capital Requirements and Sources of Liquidity

Arabella currently expects to drill an estimated 14 gross horizontal wells on Arabella’s acreage in 2014. Arabella estimates that Arabella’s capital expenditures for 2014 will be between $50 million and $75 million, which includes costs for infrastructure and non-operated wells, but does not include the cost of any land acquisitions. Arabella does not have a specific acquisition budget since the timing and size of acquisitions cannot be accurately forecasted. Arabella anticipate that while some of these expenditures will be funded by operations, the majority will come from ongoing and future outside fund raising.

However, the amount and timing of these capital expenditures is largely discretionary and within Arabella’s control. Arabella could choose to defer a portion of these planned 2014 capital expenditures depending on a variety of factors, including but not limited to raising of outside capital, the success of Arabella’s drilling activities, prevailing and anticipated prices for oil and natural gas, the availability of necessary equipment, infrastructure and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions, drilling and acquisition costs and the level of participation by other interest owners.

Additionally, while some of Arabella’s capital expenditures will be financed through operations, the majority of these costs will require outside financing.

Critical Accounting Policies

Readers of this report and users of the information contained in it should be aware that certain events may impact Arabella’s financial results based on the accounting policies in place. The policies Arabella considers to be the most significant are discussed below.

The process of preparing financial statements in conformity with accounting principles generally accepted in the United States of America (“GAAP”) requires management to make estimates and assumptions that affect reported amounts of certain assets, liabilities, revenues and expenses. Arabella believes Arabella’s estimates and assumptions are reasonable; however, actual results may differ materially from such estimates.

The selection and application of accounting policies are an important process that changes as Arabella’s business changes and as accounting rules are developed. Accounting rules generally do not involve a selection among alternatives, but involve an implementation and interpretation of existing rules and the use of judgment to the specific set of circumstances existing in Arabella’s business.

Arabella reviews its proved oil and natural gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. Arabella estimates the expected undiscounted future cash flows of its oil and natural gas properties and compares such undiscounted future cash flows to the carrying amount of the oil and natural gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, Arabella will adjust the carrying amount of the oil and natural gas properties to fair value.

The factors used to determine fair value are subject to management’s judgment and expertise and include, but are not limited to, recent sales prices of comparable properties, the present value of future cash flows, net of estimated operating and development costs using estimates of proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures and various discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flows projected. No impairment of proved oil and natural gas properties was recorded for the years ended December 31, 2013, 2012 and 2011.

 Arabella commenced its oil and gas exploration activities in 2011. During the year ended December 31, 2013, the Company’s oil and gas properties increased $12.2 million in costs. In addition, the Company had negative working capital of $1,418,006 at December 31, 2013, and has not raised additional debt or equity to drill additional wells and support higher costs and expenses in 2014. These conditions raise substantial doubt about the Company’s ability to continue as a going concern. Arabella’s ability to continue as a going concern is dependent on its ability to develop its oil and gas properties and achieve profitable operations and to generate sufficient cash flow from financing and operations to meet its obligations as they become payable. Arabella expects that it will need approximately $40 million to fund its operations during the next twelve months, which will include minimum annual property lease payments, well expenditures and operating costs and expenses.  Arabella has plans to seek additional capital through private debt for the development of its oil and gas properties and operating costs and expenses. Although there are no assurances that management’s plans will be realized, Arabella believes that it will be able to continue operations in the future.

Oil and Gas Properties

The accounting for Arabella’s business is subject to accounting rules that are unique to the oil and natural gas industry. There are two allowable methods of accounting for oil and natural gas business activities: the successful efforts method and the full cost method. Arabella follows the successful efforts method that requires that geological and geophysical costs and costs of carrying and retaining undeveloped properties are charged to expense as incurred. Costs of drilling exploratory wells that do not result in proved reserves are charged to expense. Depreciation, depletion, amortization and impairment of oil and gas properties are generally calculated on a well by well in a field by field basis versus the aggregated “full cost” pool basis under the full cost method. Additionally, gain or loss is generally recognized on all sales of natural gas and oil properties under the successful efforts method. As a result, Arabella’s financial statements will differ from those of companies that apply the full cost method since Arabella will generally reflect a lower level of capitalized costs as well as a lower oil and gas depreciation, depletion and amortization rate, and Arabella may have exploration expenses that full cost companies do not have.

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Under the full cost method, capitalized costs are amortized on a composite unit-of-production method based on proved natural gas and oil reserves. Under the full cost method, a company that maintains the same level of production year over year, may report significantly different the depreciation, depletion and amortization expense if estimated remaining reserves or future development costs change significantly. Proceeds from the sale of properties are accounted for as reductions of capitalized costs unless such sales involve a significant change in proved reserves and significantly alter the relationship between costs and proved reserves, in which case a gain or loss is recognized. The costs of unproved properties are excluded from amortization until the properties are evaluated.

Revenue

Arabella utilizes the sales method of accounting for oil and natural gas revenues whereby revenues, net of royalties, are recognized as the production is received by purchasers. The amount of gas sold may differ from the amount to which Arabella is entitled based on Arabella’s revenue interests in the properties. Arabella did not have any significant gas imbalance positions at December 31, 2013 or December 31, 2012.

Income Taxes

During 2013, 2012 and 2011, Arabella was not a taxable entity for federal income tax purposes. Accordingly, Arabella did not directly pay federal income tax. Arabella’s taxable income or loss, which may vary substantially from the net income or net loss Arabella reports in Arabella’s consolidated statement of income because of the differences in the tax deductions for drilling wells.

Arabella is subject to state income based taxes and Arabella uses the asset and liability method to account for state income taxes. Under this method of accounting for income taxes, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the consolidated 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. The effect on deferred tax assets and liabilities of a change in enacted tax rates is recognized in the statements of operations in the period that includes the enactment date. Arabella had no deferred state income taxes for the years 2013 and 2012.

ITEM 6. DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES

A. Directors and senior management

Directors and Executive Officers

Our current directors and executive officers are as follows:

Name	Age	Title
Jason Hoisager	33	Chief Executive Officer, President and Director
Terry E. Sanford	58	Chief Financial Officer
Chad D. Elliott	36	Chief Operating Officer
Berke Bakay	35	Director
Richard J. Hauser	52	Director
William B. Heyn	42	Director
Malachi Boyuls	34	Director
George P. Bush	37	Director

Jason Hoisager has been our Chief Executive Officer, President and a member of our board of directors since December 24, 2013. Mr. Hoisager was the founder and President of Arabella LLC, a company he established in 2008.  Mr. Hoisager is also the founder and President of Arabella Petroleum Company, LLC, which currently is the operator for our properties. He is responsible for asset acquisition, business planning and the overall management of a growing operating company. Prior to Arabella LLC, Mr. Hoisager served as an independent landman and was instrumental in planning strategic land purchases, identifying investment partners, acquiring leases and marketing to operators seeking entry into the resource plays of North and West Texas. He began his career in 2005 as an independent landman acquiring leases, maintaining ownership reports and managing a land crew in Reeves County. Mr. Hoisager attended Texas Tech University where he studied Finance and Accounting and discovered his interest in the oil and gas industry. Mr. Hoisager is well qualified to serve as a director of the combined company due to his extensive experience in oil and gas and in acquiring, developing and operating properties, especially in the Southern Delaware Basin.

Terry E. Sanford has been our Chief Financial Officer since December 24, 2013. Mr. Sanford has been the Chief Financial Officer of Arabella LLC since November 2013. Mr. Sanford manages the Accounting, Finance and Investor Relations departments and roles for Arabella LLC. Mr. Sanford is as CPA and has a bachelor’s degree in Accounting from Sam Houston State University and a MBA in Finance from the University of Houston. Mr. Sanford is currently on the Board of Directors of the Houston, Texas Chapter of Financial Executives International and previously served as the President of the Chapter. Mr. Sanford has served as the Controller, Chief Accounting Officer, Treasurer and Chief Financial Officer in various industries including manufacturing, construction, consumer products, financial services and real estate. Prior to joining Arabella, in 2013, Mr. Sanford was the Chief Financial Officer for Automation Technology, Inc. a privately owned company that manufactures actuators for valves on oil and gas pipelines. Mr. Sanford worked for Carriage Services, Inc. (NYSE: CSV) from 1997 to 2012 where he had substantial experience in public company financial reporting, investor relations and mergers and acquisitions. Mr. Sanford’s last position at Carriage Services, Inc. was Executive Vice President, Chief Financial Officer and Chief Accounting Officer. Prior to Carriage Services, Inc., Mr. Sanford was the Chief Financial Officer for Enduro Systems, Inc. from 1996 to 1997, a company that manufactured oil and gas refinery products nationally and internationally. Mr. Sanford worked for Petrolon, Inc., an oil lubricants company, from 1992 to 1995 as the Corporate Controller. Mr. Sanford also worked in public accounting from 1982 to 1992, including PricewaterhouseCoopers, in the audit department where he served various companies in the oil and gas industries, including Exploration and Production and Drilling Companies. Prior to his public accounting tenure, Mr. Sanford was the Treasurer for Farr Oil Tool, a privately owned company that manufactured oil and gas completion equipment.

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Chad D. Elliott has been our Chief Operating Officer since December 24, 2013. Mr. Elliott has been the Chief Operating Officer and Executive Vice President of Arabella LLC, joining the company in 2012. Chad brings over 12 years of experience in drilling operations to us and is responsible for all daily drilling activities as well as the long term organization of the company’s drilling team. Prior to joining Arabella LLC, From 1999 to 2011, Chad served in various capacities with Altura, Oxy Permian, Chesapeake and EOG Resources where he gained valued experience drilling in the Haynesville Shale, the Gulf Coast Region and the Permian Basin. Most recently, Chad served as Senior Drilling Engineer from 2011 to 2012 for Concho Resources where he supervised the New Mexico Shelf drilling program. Chad is a graduate of Texas Tech University and holds a Bachelor of Science in Petroleum Engineering.

Berke Bakay has been a member of our board of directors since inception. From inception until the close of the business combination, Mr. Bakay was the Executive Chairman of our board. Mr. Bakay has been the President and Chief Executive Officer of Kona Grill, Inc. (NASDAQ: KONA), an American grill and sushi bar (“Kona”) since January 2012. He has also serves on the board of directors of Kona. Mr. Bakay founded BBS Capital Management, LP, a Texas limited partnership that serves as the investment manager to the BBS Capital Fund, LP, in January 2008 and has served as its managing member since its formation. Prior to forming BBS Capital Management, LP, Mr. Bakay was the co-founder and co-portfolio manager of Patara Capital, L.P., an investment management firm based in Dallas, Texas from January 2006 through December 2007. From May 2005 through January 2006, Mr. Bakay was an equity analyst at Southwest Securities, Inc., a subsidiary of SWS Group, Inc. (NYSE: SWS), a financial services company, where he covered the specialty retail industry. Mr. Bakay currently serves on the board of directors of Kona Grill, Inc. (NASDAQ: KONA), an American grill and sushi bar.  Mr. Bakay graduated from Boston College, Carroll School of Management with a Bachelor of Science in finance and from Boston College, Carroll School of Management with a Master of Science in Finance. Mr. Bakay is well qualified to serve as our director as a result of his experience with public companies as well as his expertise in the capital markets.

Richard J. Hauser has been a member of our Board of Directors since December 24, 2013.  He had been a member of our advisory committee from our inception through December 24, 2013. Mr. Hauser has served as a director of Kona Grill, Inc. (NASDAQ: KONA) since December 2004. Mr. Hauser serves as the President and owner of Capital Real Estate, Inc., a commercial real estate development company based in Minneapolis, Minnesota, which he founded in 2001. In addition, Mr. Hauser is the Manager and owner of Net Lease Development, LLC, which is a controlled operating company under Capital Real Estate, Inc., as well as a member and managing partner of several other partnerships formed for real estate and related ventures. Prior to founding Capital Real Estate, Inc. and Net Lease Development, LLC, Mr. Hauser served as a partner with Reliance Development Company, LLC from 1992 to 2001, where he was responsible for the management, development, and sale of retail properties. Mr. Hauser has a strong executive background in commercial real estate and finance, with extensive experience in business operations and strategic planning. Mr. Hauser has an undergraduate degree in Business and Liberal Arts from the University of Minnesota and a graduate degree in Real Estate and Finance from the University of Denver. Mr. Hauser is well qualified to serve as our director as a result of his experience in business management and development.

William B. Heyn has been a member of our Board of Directors since December 24, 2013.  He had been a member of our advisory committee from our inception through December 24, 2013. Since 2007, Mr. Heyn has been Chief Executive Officer of Tritaurian Capital, Incorporated, a FINRA registered broker-dealer. From 2001 to the present, Mr. Heyn has been a Managing Director with Tritaurian Capital, Incorporated, and its predecessor companies. Tritaurian Capital serves small and middle market companies with investment banking, specialty financing and mergers and acquisitions advisory. Additionally, Mr. Heyn is a Managing Partner of Tritaurian Resources, Incorporated an international commodities broker and advisory firm. From 2004 to the present, Mr. Heyn has been a partner in E. J. McKay & Co., Inc., an international investment bank based in Shanghai. Prior to 2001, Mr. Heyn held various investment banking positions in the financial industry including in the Investment Banking Division of Merrill Lynch, the Mergers and Acquisitions Group of J. P. Morgan and the Corporate Finance Department of Morgan Stanley. Mr. Heyn was an advisor to CS China Acquisition Corp., a Specified Purpose Acquisition Corporation that subsequently merged with a target in China to form Iao Kun Group Holdings Company Limited (previously known as Asia Entertainment & Resources Ltd.), which is listed on the NASDAQ Stock Market (NASDAQ: IKGH). Mr. Heyn was an advisor to China Unistone Acquisition Corp., a Specified Purpose Acquisition Corporation that subsequently merged with a target in China to form Yucheng Technologies Limited, which is listed on the Nasdaq Capital Market (NASDAQ: YTEC). Mr. Heyn received a B.A. from Yale University with majors in history and political science and currently holds Series 7, 24, 63, 79 and 99 securities licenses. Mr. Heyn is well qualified to serve as our director as a result of his experience in capital markets, mergers and acquisitions and public company corporate governance and management.

Malachi Boyuls has been a member of our board of directors since January 30, 2014.  Since December 2012, Mr. Boyuls has been a partner in St. Augustine Capital Partners, LLC, a Texas-based partnership focused on principal investing, brokering and consulting services for small to middle-market transactions in the oil and gas industry. Prior to this business venture, from June 2012 to December 2012, he served as Senior Vice President and Counsel of Thomas Title, a commercial real estate business. He also practiced law in the Dallas office of Gibson, Dunn, & Crutcher LLP from August 2008 to June 2012, where he practiced in the firm’s regulatory groups, including antitrust, energy, securities, and intellectual property.  During law school Mr. Boyuls interned for now-Justice Samuel A. Alito, Jr.  Following law school, he served as law clerk to Hon. David C. Godbey on the United States District Court for the Northern District of Texas, and then for Hon. Harris L Hartz on the United States Court of Appeals for the Tenth Circuit.  Mr. Boyuls is active in the community, serving on the budget committee for his local school board and on the North Texas Council for Southern Methodist University’s Maguire Energy Institute.  In 2010 Governor Perry appointed him to the Texas Appraiser Licensing and Certification Board, where he served as Chairman of the Board’s budget committee.  Mr. Boyuls is also active in Republican politics, having served on the Republican Party of Texas’s finance committee and on the board of Maverick PAC, a national political action committee dedicated to engaging the next generation of Republican voters. Mr. Boyuls earned his J.D. from New York University School of Law, where he was Editor-in-Chief of the Annual Survey of American Law. He earned his B.A. in Religion from the University of Mary Hardin Baylor where he was voted Team Captain of the football team, earned Academic All-Conference honors, and was involved in a variety of community service causes. Mr. Boyuls is well qualified to serve as our director as a result of his extensive regulatory and business background and experiences.

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George P. Bushhas been a member of our board of directors since January 30, 2014.  Mr. Bush founded and has been a partner in St. Augustine Capital Partners, LLC, a Texas-based partnership focused on principal investing, brokering and consulting services for small to middle-market transactions in the oil and gas industry since May 2012.  In 2007, Mr. Bush co-founded Pennybacker Capital LLC, a real estate private equity firm. From 2004 to 2006, Mr. Bush was a corporate attorney at Akin Gump Strauss Hauer & Feld LLP, one of the nation’s leading law firms.  Prior to joining Akin Gump, George P. served as a surrogate speaker on the George W. Bush presidential campaign from 1999 to the general election in 2000.   In 2006, George P. Bush joined the U.S. Naval Reserves through the Direct Commission Officer program. In 2010, he began an eight-month tour of duty in Afghanistan in support of Operation Enduring Freedom under the Special Operations Command. Among other service decorations, he was awarded the Joint Service Commendation Medal for his meritorious service. George P. Bush has deep roots in the Republican Party. He has assisted and supported many GOP campaigns beyond those of his uncle and father. He has served as the Deputy Finance Chair for the Republican Party of Texas and co-founded the Hispanic Republicans of Texas. George P. Bush is also the past national co-chair of Maverick PAC, a national political action committee dedicated to engaging the next generation of Republican voters.  In November 2012, George P. Bush filed papers with the Texas Ethics Commission declaring himself a candidate for public office in 2014. Mr. Bush received his undergraduate degree from Rice University in 1998 and his J.D. from The University of Texas School of Law in 2003. Mr. Bush is well qualified to serve as our director as a result of his broad experiences as an energy professional and military veteran.

Family relationships

Chad D. Elliott, Arabella’s Chief Operating Officer and Executive Vice President, is married to Misty Elliott, Arabella’s Controller and is the son of Bill Elliott who is Arabella’s production engineer.

B. Compensation

Director Compensation

We currently do not pay any compensation to members of our board of directors. Future compensation to be paid to our directors, if any, will be determined in the future.

Executive Compensation

Overview of our Executive Compensation

We currently pay annual base salaries to each of Jason Hoisager, Terry E. Sanford and Chad D. Elliott of $300,000, $280,000 and $275,000, respectively. In 2013, Arabella Petroleum Company paid Mr. Elliott $140,447 in the form of salary and bonuses and Mr. Sanford was paid $7,100 in consulting fees and $37,692 in salary and wages. Mr. Hoisager did not receive any compensation in 2013.

Grants of Plan Based Awards

None of our named executives currently participates in or have account balances in any plan based award programs. Future bonus plans will be adopted by the board of directors.

Employment Agreements

On December 24, 2013, we entered into an employment agreement with Jason Hoisager pursuant to which Mr. Hoisager agreed to act as our Chief Executive Officer and President. The employment agreement has a term of one year and will automatically renew for additional one-year terms after the end of the initial term if the agreement is not terminated at least 90 days prior to the end of the applicable term. The employment agreement provides for a base salary of $300,000 a year, with bonus determined by our board of directors. If the board of directors terminates the agreement without cause, Mr. Hoisager terminates the employment agreement for good reason, or Mr. Hoisager’s employment is terminated within six months after a change in control, Mr. Hoisager will be entitled to severance equal to 24 months of his base salary and an amount equal to his bonus for the prior year.

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Outstanding Equity Awards at Fiscal Year-End; Option Exercises and Stock Vested

As of the date hereof, none of our named executives have held compensation based options to purchase interests in us or other awards with values based on the value of our interests.  Mr. Hoisager and Mr. Elliott are entitled to receive ordinary shares pursuant to certain earnout provisions contained in the documentation relating to the Acquisition – “Agreement and Plan of Merger and Reorganization – Acquisition Consideration”.

Pension Benefits

None of our named executives currently participates in or has account balances in qualified or nonqualified defined benefit plans sponsored by us.

Nonqualified Deferred Compensation

None of our named executives currently participates in or has account balances in nonqualified defined contribution plans or other deferred compensation plans maintained by us.

Potential Payments upon Termination or Change in Control

Mr. Hoisager’s employment agreement provides for certain payments in the event of his termination or a change in control of the company.  If the board of directors terminates the agreement without cause, Mr. Hoisager terminates the employment agreement for good reason, or Mr. Hoisager’s employment is terminated within six months after a change of control, Mr. Hoisager will be entitled to severance equal to 24 months of his base salary and an amount equal to his bonus for the prior year.

C.       Board Practices

Board Committees

Arabella’s board of directors has established an audit committee, a compensation committee and a nominating committee.

Audit Committee.  The audit committee currently consists of William B. Heyn.  Additional members are expected to be appointed in the near future. Mr. Heyn will be the chair of the audit committee, and the board of directors believes that Mr. Heyn qualifies as an “audit committee financial expert”, as such term is defined in the rules of the Securities and Exchange Commission.  Arabella’s board of directors intends to adopt an audit committee charter in the near future.

Compensation Committee.  The compensation committee consists of Berke Bakay and Malachi Boyuls. Mr. Bakay is the chair of Arabella’s compensation committee. Berke Bakay and Malachi Boyuls do not have any direct or indirect material relationship with Arabella other than as a director.  Arabella’s board of directors intends to adopt a compensation committee charter in the near future.

Nominating Committee.  The nominating and corporate governance committee consists of George P. Bush and Richard Hauser. Mr. Bush is the chair of our nominating and corporate governance committee. George P. Bush and Richard Hauser do not have any direct or indirect material relationship with Arabella other than as a director.  Arabella’s board of directors intends to adopt a nominating committee charter in the near future

In making nominations, the nominating committee is required to submit candidates who have the highest personal and professional integrity, who have demonstrated exceptional ability and judgment and who shall be most effective, in conjunction with the other nominees to the board, in collectively serving the long-term interests of the shareholders. In evaluating nominees, the nominating committee is required to take into consideration the following attributes, which are desirable for a member of the board: leadership, independence, interpersonal skills, financial acumen, business experiences, industry knowledge, and diversity of viewpoints.

Director Independence

Arabella’s Board of Directors has determined that Messrs. George P. Bush, Malachi Boyuls, Richard Hauser, Berke Bakay and William B. Heyn qualify as independent directors under the rules of the Nasdaq Stock Market because they are not currently employed by Arabella, and do not fall into any of the enumerated categories of people who cannot be considered independent in the Nasdaq Stock Market Rules.

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D.       Employees

As at December 31, 2013, we had three executive officers and 17 employees. None of Arabella’s employees are represented by labor unions or covered by any collective bargaining agreements. Arabella also hires independent contractors and consultants involved in land, technical, regulatory and other disciplines to assist Arabella’s full time employees.

E.       Share Ownership

See Item 7, below.

ITEM 7. MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS

A.        Major shareholders

The following table sets forth information with respect to the beneficial ownership, within the meaning of Rule 13d-3 under the Exchange Act, of our ordinary shares, as of April 30, 2014:

● each person known to us to own beneficially more than 5% of our ordinary shares;

● each of our directors and executive officers; and

● all of our directors and executive officers as a group.

Beneficial ownership includes voting or investment power with respect to the securities and takes into consideration options or warrants exercisable by a person within 60 days after April 30, 2014. Except as indicated below, and subject to applicable community property laws, the persons named in the table have sole voting and investment power with respect to all securities shown as beneficially owned by them.

Name and Address (1)	Number of Shares Beneficially Owned		Percentage of Ownership (2)
Directors and executive officers:
Berke Bakay(3)		3,287,355		42.4
Jason Hoisager		1,469,012		30.4
Terry E. Sanford		0		*
Chad D. Elliott		130,032		2.7
Richard J. Hauser(4)		3,278,428		42.2
William B. Heyn(5)		267,664		5.4
George P. Bush		0		*
Malachi Boyuls		0		*
All directors and executive officers as a group (8 individuals)		8,432,491		77.6
Principal shareholders:
BBS Capital Fund, LP(3)		3,278,428		42.2
Hauser Holdings LLC(4)		3,278,428		42.2
Greg McCabe		1,003,597		20.8
Travis Street Energy, LLC(6)		312,500		6.5
John V. Calce(7)		267,662		5.4
James R. Preissler(8)		267,662		5.4

*	less than one percent (1%).
(1)	Unless otherwise noted, the business address for each of our beneficial owners is 500 W. Texas Avenue, Suite 1450, Midland, Texas 79701.
(2)	Based on 4,829,826 ordinary shares outstanding as of April 30, 2014, excluding treasury shares. Options or warrants exercisable within 60 days of April 30, 2014 are deemed to be outstanding for the purpose of computing the percentage ownership of the indicated individual or group, but are not deemed to be outstanding for the purpose of computing the percentage ownership of any other person shown in the table.
(3)	The number of ordinary shares beneficially owned by Mr. Bakay consists of (i) 345,928 ordinary shares beneficially owned by BBS Capital Fund, LP, (ii) 8,927 ordinary shares owned by Mr. Bakay, and (iii) warrants exercisable for 2,932,500 ordinary shares, all of which are owned by BBS Capital Fund, LP. Mr. Bakay and BBS Capital Fund, LP have sole voting and dispositive power over all suchsecurities. The address of BBS Management Group is 5524 E. Estrid Avenue, Scottsdale, Arizona 85254. Messrs. Heyn, Calce and Preissler each have an option to purchase warrants to purchase 247,500 shares (742,500 in the aggregate) from BBS Capital Fund, LP.
(4)	The number of ordinary shares beneficially owned by Mr. Hauser consists of (i) 345,928 ordinary shares beneficially owned by Hauser Holdings, LLC, and (ii) warrants exercisable for 2,932,500 ordinary shares, all of which are owned by Hauser Holdings, LLC. Mary Jane Hauser has sole voting and dispositive power over all securities held by Hauser Holdings LLC. The address of Hauser Holdings LLC is 50 South Sixth Street, Minneapolis, Minnesota 55402. Ms. Hauser is the wife of Richard J. Hauser, one of our directors. Messrs. Heyn, Calce and Preissler each have an option to purchase warrants to purchase 247,500 shares (742,500 in the aggregate) from Hauser Holdings, LLC.

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(5)	The number of ordinary shares beneficially owned by Mr. Heyn consists of (i) 102,664 ordinary shares and (ii) warrants exercisable for 165,000 ordinary shares. Mr. Heyn has an option from each of BBS Capital Fund, LP and Hauser Holdings, LLC to purchase warrants to purchase 247,500 shares (495,000 in the aggregate).
(6)	Mark G. Avery has sole voting and dispositive power over all ordinary shares held by Travis Street Energy, LLC. The address of Travis Street Energy, LLC is 712 S. Main Street, Suite 1200, Houston, Texas 77002.
(7)	The number of ordinary shares beneficially owned by Mr. Calce consists of (i) 102,662 ordinary shares and (ii) warrants exercisable for 165,000 ordinary shares. The business address of Mr. Calce is 17950 Preston Road, Suite 1080A Dallas, Texas 75252. Mr. Calce has an option from each of BBS Capital Fund, LP and Hauser Holdings, to purchase warrants to purchase 247,500 shares (495,000 in the aggregate).
(8)	The number of ordinary shares beneficially owned by Mr. Preissler consists of (i) 102,662 ordinary shares and (ii) warrants exercisable for 165,000 ordinary shares. The business address of Mr. Preissler is 50 Old Route 25A Fort Salonga, NY 11768. Mr. Preissler has an option from each of BBS Capital Fund, LP and Hauser Holdings, LLC to purchase warrants to purchase 247,500 shares (495,000 in the aggregate).

As of April 30, 2014, approximately 100% of our outstanding ordinary shares are held by fifteen record holders in the United States.

Voting Agreement

The Merger Agreement provided that, upon closing of the Acquisition, four persons on the combined company’s board of directors will be designated by Arabella LLC and three persons will be designated by us. In addition, our shareholders, Arabella’s members and certain of our founding shareholders entered into a voting agreement that provided that, for the four year period following the Acquisition, such of our founding shareholders will designate three persons as nominees to the combined company’s board of directors and Arabella LLC’s members will designate four persons as nominees to the our board of directors, and that each of the parties to the voting agreement will take all action necessary to elect such persons to the board of directors of the combined company. The voting agreement will also provide that the company may not take the following actions without the approval of two-thirds of the members of the board of directors and at least one person designated by our founding shareholders voting in favor:

● Issue any ordinary share of the Arabella or securities convertible into ordinary shares;

● Repay the loan in the amount of $3,007,170 from Jason Hoisager to Arabella described below;

● Appoint or remove the combined company’s Chief Executive Officer or Chief Financial Officer;

● Amend the Merger Agreement;

● Amend the Public Peer Set (as defined in the Merger Agreement);

● Retain an investor relations firm;

● Appoint or hire an employee to provide internal investment relations management; and

● Adopt an equity incentive plan for officers, directors or employees.

B        Related Party Transactions

Immediately prior to the consummation of our IPO, certain of our initial shareholders purchased an aggregate of 6,600,000 warrants for an aggregate purchase price of $2,310,000, or $0.35 per warrant. We refer to these warrants as the “insider warrants.” The insider warrants are identical to the warrants underlying the units sold in our IPO, except that the insider warrants may be exercised on a cashless basis so long as such warrants are held by the purchasers or permitted assigns. Such purchasers have also agreed that the insider warrants will not be sold or transferred by them until after we have completed a business combination.

Concurrently with our IPO, we issued to EarlyBirdCapital, Inc. (“EBC”), the representative of the underwriters of our IPO as additional compensation, for a purchase price of $100, a unit purchase option to purchase 400,000 units for $8.80 per unit. The units issuable upon exercise of this option are identical to those sold in the IPO, with the exception of containing a provision for cashless exercise by EBC. The unit purchase option is currently exercisable, in whole or in part, and expires on March 16, 2016.

The holders of the initial shares, as well as the holders of the insider warrants (and underlying securities), will be entitled to registration rights pursuant to an agreement that was signed at the time of our IPO. The holders of our initial shares issued and outstanding on March 16, 2011, as well as the holders of the insider warrants (and underlying securities), will be entitled to registration rights pursuant to an agreement that was signed on March 16, 2011. The holders of the majority of these securities are entitled to make up to two demands that we register such securities. The holders of the majority of the initial shares can elect to exercise these registration rights at any time commencing three months prior to the date on which these ordinary shares are to be released from escrow. The holders of a majority of the insider warrants (or underlying securities) can elect to exercise these registration rights at any time after we consummate a business combination. In addition, the holders have certain “piggy-back” registration rights with respect to registration statements filed subsequent to our consummation of a business combination. We will bear the expenses incurred in connection with the filing of any such registration statements.

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Below is a list of companies that Jason Hoisager has had, or currently has, an interest in, along with a description of the relationship to that company with Arabella LLC:

Arabella Petroleum Company, LLC (APC) is the operator of record for properties owned by Arabella. APC is expected to continue operating these properties until Arabella Exploration is eligible to do so.  APC is owned by Jason Hoisager.  Arabella owes $3,695,119 for joint interest billings to APC as of December 31, 2013. As of December 31, 2013, APC owes Arabella $425,372 in its proportionate share of revenues from oil and gas sales.  During 2013, Arabella paid APC $3,589,903 in capital costs associated with Arabella’s portion of well drilling and maintenance costs incurred by APC.

APC owns or has owned all right, title and interest in the personal property (both tangible and intangible property) that is necessary for Arabella to conduct business. APC and Arabella have a cost sharing agreement in place, but APC has agreed to convey all of these rights necessary for Arabella to conduct its business to Arabella as soon as practicable.

Trans-Texas Land & Title, LLC (TTLT) has performed mineral ownership reports on lands for Arabella in the past, and may do so in the future. Mr. Hoisager owns 100% of the equity interests of TTLT. There was an intercompany transfer of $3,500 in 2011. The funds were transferred into Arabella Exploration, LLC and then transferred out of Arabella Exploration, LLC less than one week later.

Arabella was indebted to Jason Hoisager for $3,007,170 as of December 31, 2013, which relates to oil and gas properties that Mr. Hoisager had APC transfer at cost to Arabella. This indebtedness is evidenced by a subordinated unsecured promissory note, which note bears no interest and matures in 2023.

On May 1, 2014 Arabella received a loan from Hauser Holdings, LLC an affiliate of Richard Hauser, one of our directors.  The $800,000 loan is due August 31, 2014 and bears an interest rate of 10% per annum.

C.       Interests of Experts and Counsel

Not required.

ITEM 8. FINANCIAL INFORMATION

A.       Financial Statements and Other Financial Information.

See Item 18.

B.       Significant Changes

See Item 4 Above.

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ITEM 9. THE OFFER AND LISTING

A.       Offer and Listing Details

The following tables set forth, for the periods indicated and through April 30, 2014, the high and low sale prices for our units, ordinary shares and warrants, respectively, as reported on the Over-the-Counter Bulletin Board. (See Item 9C for the dates that the securities were traded on each market).

	Units				Ordinary Shares				Warrants
	High		Low		High		Low		High		Low
Annual Highs and Lows
Year ended December 31, 2014*		8.25		8.25		8.28		5.71		1.30		0.60
Year ended December 31, 2013		8.35		8.17		8.25		7.25		0.85		0.06
Year ended December 31, 2012		8.20		8.10		8.00		7.75		0.37		0.10
Year ended December 31, 2011(from March 21)		8.20		7.98		7.75		7.75		0.39		0.27
Fiscal Quarterly Highs and Lows 2011
First Quarter (from March 21)		8.03		7.98		--		--		--		--
Second Quarter		8.05		7.98		--		--		--		--
Third Quarter		8.05		8.05		7.75		7.75		0.39		0.38
Fourth Quarter		8.20		8.07		7.75		7.75		0.30		0.27
Fiscal Quarterly Highs and Lows 2012
First Quarter		8.20		8.20		7.75		7.75		0.36		0.25
Second Quarter		8.20		8.10		7.85		7.75		0.37		0.20
Third Quarter		8.20		8.10		7.90		7.77		0.30		0.20
Fourth Quarter		8.20		8.20		8.00		7.89		0.33		0.10

Fiscal Quarterly Highs and Lows 2013
First Quarter	8.35	8.17	8.18	8.18	0.22	0.06
Second Quarter	8.30	8.17	8.08	8.08	0.55	0.23
Third Quarter	8.25	8.25	8.13	8.08	0.45	0.11
Fourth Quarter	8.25	8.25	8.25	7.25	0.85	0.22
Fiscal Quarterly Highs and Lows 2014
First Quarter	8.25	8.25	8.28	6.01	1.30	0.60
Second Quarter*	8.25	8.25	7.05	5.71	1.30	0.98
Monthly Highs and Lows
November 2013	8.25	8.25	8.13	8.13	0.45	0.26
December 2013	8.25	8.25	8.25	7.25	0.85	0.25
January 2014	8.25	8.25	7.85	6.51	0.92	0.60
February 2014	8.25	8.25	7.20	6.51	0.95	0.70
March 2014	8.25	8.25	8.28	6.01	1.30	0.87
April 2014*	8.25	8.25	7.05	5.71	1.30	0.98

* Through April 30, 2014

The closing bid for our ordinary shares on April 30, 2014 was $5.71.

B.       Plan of Distribution

Not Applicable.

C.       Markets

Our units have been quoted on the Over-the-Counter Bulletin Board under the symbol LOKAF since March 21, 2011 and under the symbol AXPUF since February 27, 2014. Our ordinary shares have been quoted on the Over-the-Counter Bulletin Board under the symbol LOKKF since June 15, 2011 and under the symbol AXPLF since February 27, 2014. Our warrants have been quoted on the Over-the-Counter Bulletin Board under the symbol LOKWF since June 15, 2011 and under the symbol AXLWF since February 27, 2014.

D.       Selling Shareholders

Not Applicable.

E.        Dilution

Not Applicable.

F.        Expenses of the Issue

Not Applicable.

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ITEM 10. ADDITIONAL INFORMATION

A.       Share Capital

Not Applicable.

B.       Memorandum and Articles of Association

Amended and Restated Memorandum and Articles of Association

Registered Office. Under our Amended and Restated Memorandum and Articles of Association, our Registered Office is located at the offices of Codan Trust Company (Cayman) Limited, Cricket Square, Hutchins Drive, PO Box 2681, Grand Cayman, KY1-1111, Cayman Islands.

Objects and Purposes. Under Article 3 of our Amended and Restated Memorandum and Articles of Association, the objects for which we are established are unrestricted.

Directors. Under Article 94 of our Articles of Association, no contract or transaction between us and one or more of our Directors (an “Interested Director”) or officers, or between us and any of their affiliates (an “Interested Transaction”), will be void or voidable solely for this reason, or solely because the director or officer is present at or participates in the meeting of our board or committee which authorizes the contract or transaction, or solely because any such director’s or officer’s votes are counted for such purpose, if:

(a) The material facts as to the director’s or officer’s relationship or interest and as to the contract or transaction are disclosed or are known to the board of directors or the committee, and the board or committee in good faith authorizes the contract or transaction by the affirmative votes of a majority of the disinterested directors, even though the disinterested directors be less than a quorum; or

(b) The material facts as to the director’s or officer’s relationship or interest and as to the contract or transaction are disclosed or are known to our shareholders entitled to vote thereon, and the contract or transaction is specifically approved in good faith by vote of our shareholders; or

(c) The contract or transaction is fair as to us as of the time it is authorized, approved or ratified, by the board, a committee or the shareholders.

A majority of independent directors must vote in favor of any Interested Transaction and determine that the terms of the Interested Transaction are no less favorable to us than those that would be available to us with respect to such a transaction from unaffiliated third parties.

Rights, Preferences and Restrictions Attaching to Our Ordinary Shares. We are authorized to issue 50,000,000 ordinary shares, par value $0.001 and 5,000,000 shares of preferred stock, par value $0.001 per share. As of the date of this report, 4,829,826 ordinary shares are issued and outstanding. Each ordinary share has the right to one vote at a meeting of shareholders or on any resolution of shareholders, the right to an equal share in any dividend paid by us, and the right to an equal share in the distribution of surplus assets. We may by a resolution of the board of directors redeem our ordinary shares for such consideration as the board of directors determines.

If, at any time, our share capital is divided into different classes of shares, the rights attached to any class (unless otherwise provided by the terms of issue of the shares of that class) may, whether or not we are being wound-up, be varied with the consent in writing of the holders of three-fourths of the issued shares of that class or with the sanction of a resolution passed by a majority of the votes cast at a separate general meeting of the holders of the shares of the class at which meeting the necessary quorum shall be two persons at least holding or representing by proxy one-third of the issued shares of the class.

Additional information regarding our securities is included under the heading “Description of Securities” in our registration statement on Form F-1 (File No. 333-172334), initially filed with the Securities and Exchange Commission on February 18, 2011, as amended, which is incorporated herein by reference.

Our annual meeting may be held at such time and place as their chairman or any two directors or any director and the secretary or the board of directors shall appoint. The chairman or any two directors or any director and the secretary or the board of directors may convene an extraordinary general meeting whenever in their judgment such a meeting is necessary. At least 10 clear days’ notice of an annual meeting shall be given to each shareholder entitled to attend and vote thereat, stating the date, place, and time at which the meeting is to be held, and if different, the record date for determining shareholders entitled to attend and vote at the annual meeting, and, if practicable, the other business to be conducted at the meeting. At least 10 clear days’ notice of an extraordinary general meeting shall be given to each shareholder entitled to attend and vote thereat, stating the date, place, and time at which the meeting is to be held, and the general nature of the business to be considered at the meeting. A meeting shall, notwithstanding the fact that it is called on shorter notice than otherwise required, be deemed to have been properly called if it is so agreed by (i) all of the shareholders entitled to attend and vote thereat in the case of an annual meeting, and (ii) 75% of the shareholders entitled to attend and vote thereat in the case of an extraordinary general meeting. The accidental omission to give notice of a meeting to, or the non-receipt of a notice of a meeting by, any person entitled to receive notice shall not invalidate the proceedings at that meeting.

There are no limitations on the rights to own our securities, or limitations on the rights of non-resident or foreign shareholders to hold or exercise voting rights on our securities, contained in our Amended and Restated Memorandum and Articles of Association (or under Cayman Islands law).

C.       Material Contracts

Information concerning our material contracts governing the business of the Company is included elsewhere in this report or in the information incorporated by reference herein.

On December 24, 2013, we entered into an employment agreement with Jason Hoisager pursuant to which Mr. Hoisager agreed to act as our Chief Executive Officer and President. The employment agreement has a term of one year and will automatically renew for additional one-year terms after the end of the initial term if the agreement is not terminated at least 90 days prior to the end of the applicable term. The employment agreement provides for a base salary of $300,000 a year, with bonus determined by our board of directors. If we terminate the employment agreement without cause, Mr. Hoisager terminates the employment agreement for good reason, or Mr. Hoisager’s employment is terminated within six months after a change in control, Mr. Hoisager will be entitled to severance equal to 24 months of his base salary and an amount equal to his bonus for the prior year.

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On December 24, 2013, we entered into a registration rights agreement with the former members of Arabella LLC pursuant to which we granted such members the right to make up to two demands that we register the securities received in connection with the Business Combination. In addition, the former members of Arabella LLC have certain “piggy-back” registration rights with respect to registration statements filed subsequent to our consummation of a business combination. We will bear the expenses incurred in connection with the filing of any such registration statements.

D.       Exchange controls

Under Cayman Islands law, there are currently no restrictions on the export or import of capital, including foreign exchange controls or restrictions that affect the remittance of dividends, interest or other payments to nonresident holders of our shares.

E.       Taxation

The following summary of the material Cayman Islands and U.S. federal income tax consequences of an investment in our units, ordinary shares and warrants to acquire ordinary shares, which are sometimes referred to in this summary collectively, or individually, as our “securities,” is based upon laws and relevant interpretations thereof in effect as of the date of this report, all of which are subject to change. This summary does not deal with all possible tax consequences relating to an investment in our securities, such as the tax consequences under state, local and other tax laws.

Cayman Islands Taxation

The Government of the Cayman Islands will not, under existing legislation, impose any income, corporate or capital gains tax, estate duty, inheritance tax, gift tax or withholding tax upon us or our shareholders. The Cayman Islands are not party to any double taxation treaties.

No Cayman Islands stamp duty will be payable by our security holders in respect of the issue or transfer of our securities. However, an instrument transferring title to our securities, if brought to or executed in the Cayman Islands, would be subject to Cayman Islands stamp duty.

We have received an undertaking from the Governor-in-Cabinet of the Cayman Islands that, in accordance with section 6 of the Tax Concessions Law (Revised) of the Cayman Islands, for a period of 20 years from the date of the undertaking, no law which is enacted in the Cayman Islands imposing any tax to be levied on profits, income, gains or appreciations shall apply to us or our operations and, in addition, that no tax to be levied on profits, income, gains or appreciations or which is in the nature of estate duty or inheritance tax shall be payable (i) on our securities or our debentures or other obligations or (ii) by way of the withholding in whole or in part of a payment of dividend or other distribution of income or capital by us to our security holders or a payment of principal or interest or other sums due under a debenture or other obligation.

United States Federal Income Taxation

General

The following is a summary of the material U.S. federal income tax consequences of the acquisition, ownership, and disposition of our securities. Because the components of a unit are separable at the option of the holder, the holder of a unit should be treated, for U.S. federal income tax purposes, as the owner of the underlying ordinary share and warrant components of the unit, as the case may be. As a result, the discussion below of the U.S. federal income tax consequences with respect to actual holders of ordinary shares and warrants also should apply to the holders of units (as the deemed owners of the ordinary shares and warrants underlying the units).

The discussion below of the U.S. federal income tax consequences to “U.S. Holders” will apply to a beneficial owner of our securities that is treated for U.S. federal income tax purposes as:

● an individual citizen or resident of the United States;

● a corporation (or other entity treated as a corporation) that is created or organized (or treated as created or organized) in or under the laws of the United States, any state thereof or the District of Columbia;

● an estate whose income is includible in gross income for U.S. federal income tax purposes regardless of its source; or

● a trust if (i) a U.S. court can exercise primary supervision over the trust’s administration and one or more U.S. persons are authorized to control all substantial decisions of the trust, or (ii) it has a valid election in effect under applicable U.S. Treasury regulations to be treated as a U.S. person.

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If a beneficial owner of our securities is not described as a U.S. Holder and is not an entity treated as a partnership or other pass-through entity for U.S. federal income tax purposes, such an owner will be considered a “Non-U.S. Holder.” The material U.S. federal income tax consequences of the acquisition, ownership and disposition of our securities applicable specifically to Non-U.S. Holders are described below under the heading “Non-U.S. Holders.”

This summary is based on the Internal Revenue Code of 1986, as amended (the “Code”), its legislative history, Treasury regulations promulgated thereunder, published rulings and court decisions, all as currently in effect. These authorities are subject to change or differing interpretations, possibly on a retroactive basis.

This discussion does not address all aspects of U.S. federal income taxation that may be relevant to any particular holder of our securities based on such holder’s individual circumstances. In particular, this discussion considers only holders that own and hold our securities as capital assets within the meaning of Section 1221 of the Code and does not address the alternative minimum tax. In addition, this discussion does not address the U.S. federal income tax consequences to holders that are subject to special rules, including:

● financial institutions or financial services entities;

● broker-dealers;

● persons that are subject to the mark-to-market accounting rules under Section 475 of the Code;

● tax-exempt entities;

● governments or agencies or instrumentalities thereof;

● insurance companies;

● regulated investment companies;

● real estate investment trusts;

● certain expatriates or former long-term residents of the United States;

● persons that actually or constructively own 5% or more of our voting shares;

● persons that acquired our securities pursuant to the exercise of employee options, in connection with employee incentive plans or otherwise as compensation;

● persons that hold our securities as part of a straddle, constructive sale, hedging, conversion or other integrated transaction;

● persons whose functional currency is not the U.S. dollar;

● controlled foreign corporations; or

● passive foreign investment companies.

This discussion does not address any aspect of U.S. federal non-income tax laws, such as gift or estate tax laws, state, local or non-U.S. tax laws or, except as discussed herein, any tax reporting obligations applicable to a holder of our securities. Additionally, this discussion does not consider the tax treatment of partnerships or other pass-through entities or persons who hold our securities through such entities. If a partnership (or other entity classified as a partnership for U.S. federal income tax purposes) is the beneficial owner of our securities, the U.S. federal income tax treatment of a partner in the partnership generally will depend on the status of the partner and the activities of the partnership. This discussion also assumes that any distributions made (or deemed made) by us on our securities and any consideration received (or deemed received) by a holder in consideration for the sale or other disposition of our securities will be in U.S. dollars.

We have not sought, and will not seek, a ruling from the Internal Revenue Service (“IRS”) or an opinion of counsel as to any U.S. federal income tax consequence described herein. The IRS may disagree with the description herein, and its determination may be upheld by a court. Moreover, there can be no assurance that future legislation, regulations, administrative rulings or court decisions will not adversely affect the accuracy of the statements in this discussion.

THIS DISCUSSION IS ONLY A SUMMARY OF THE MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES OF THE ACQUISITION, OWNERSHIP AND DISPOSITION OF OUR SECURITIES. IT IS NOT TAX ADVICE. EACH HOLDER OF OUR SECURITIES IS URGED TO CONSULT ITS OWN TAX ADVISOR WITH RESPECT TO THE PARTICULAR TAX CONSEQUENCES TO SUCH HOLDER OF THE ACQUISITION, OWNERSHIP AND DISPOSITION OF OUR SECURITIES, INCLUDING THE APPLICABILITY AND EFFECT OF ANY STATE, LOCAL, AND NON-U.S. TAX LAWS, AS WELL AS U.S. FEDERAL TAX LAWS, AND ANY APPLICABLE TAX TREATIES.

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Allocation of Purchase Price of a Unit

While not free from doubt, each unit should be treated for U.S. federal income tax purposes as an investment unit consisting of one ordinary share and one warrant to acquire one ordinary share. For U.S. federal income tax purposes, each holder of a unit generally must allocate the purchase price of a unit between the ordinary share and the warrant that comprise the unit based on the relative fair market value of each at the time of acquisition. The price allocated to the ordinary share and the warrant generally will be the holder’s tax basis in such share or warrant, as the case may be.

U.S. Holders

Taxation of Cash Distributions Paid on Ordinary Shares

Subject to the passive foreign investment company (“PFIC”) rules discussed below, a U.S. Holder generally will be required to include in gross income as ordinary income the amount of any cash dividend paid on our ordinary shares. A cash distribution on such shares generally will be treated as a dividend for U.S. federal income tax purposes to the extent paid out of our current or accumulated earnings and profits (as determined under U.S. federal income tax principles). Such dividend generally will not be eligible for the dividends-received deduction generally allowed to domestic corporations in respect of dividends received from other domestic corporations. The portion of such distribution, if any, in excess of such earnings and profits generally will constitute a return of capital that will be applied against and reduce the U.S. Holder’s adjusted tax basis in its ordinary shares (but not below zero). Any remaining excess will be treated as gain from the sale or other taxable disposition of such ordinary shares and will be treated as described under “Taxation on the Disposition of Ordinary Shares and Warrants” below.

With respect to non-corporate U.S. Holders, such dividends may be subject to U.S. federal income tax at the lower applicable long-term capital gains tax rate (see “— Taxation on the Disposition of Ordinary Shares and Warrants,” below) provided that (1) our ordinary shares are readily tradable on an established securities market in the United States, (2) we are not a PFIC, as discussed below, for either the taxable year in which the dividend was paid or the preceding taxable year, and (3) certain holding period requirements are met. It is not entirely clear, however, whether a U.S. Holder’s holding period for our ordinary shares would be suspended for purposes of clause (3) above for the period that such holder had a right to have such ordinary shares redeemed by us. Under published IRS authority, our ordinary shares are considered for purposes of clause (1) above to be readily tradable on an established securities market in the United States only if they are listed on certain exchanges, which presently do not include the Over-the-Counter Bulletin Board (the only exchange on which our ordinary shares are currently quoted and traded). Accordingly, any cash dividends paid on our ordinary shares are not currently expected to qualify for the lower rate. U.S. Holders should consult their own tax advisors regarding the availability of the lower rate for any cash dividends paid with respect to our ordinary shares.

Possible Constructive Distributions with Respect to Warrants

The terms of each warrant provide for an adjustment to the number of ordinary shares for which the warrant may be exercised or to the exercise price of the warrant in certain events.  An adjustment that has the effect of preventing dilution generally is not taxable. However, the U.S. Holders of the warrants would be treated as receiving a constructive distribution from us if, for example, the adjustment increases the warrant holders’ proportionate interest in our assets or earnings and profits (e.g., through a decrease in the exercise price of the warrants) as a result of a distribution of cash to the holders of our ordinary shares, which is taxable to the U.S. Holders of such ordinary shares as described under “— Taxation of Cash Distributions Paid on Ordinary Shares,” above. Such constructive distribution would be subject to tax as described under that section in the same manner as if the U.S. Holders of the warrants received a cash distribution from us equal to the fair market value of such increased interest.

Taxation on the Disposition of Ordinary Shares and Warrants

Upon a sale or other taxable disposition of our ordinary shares or warrants (which, in general, would include a distribution in connection with a redemption of our ordinary shares or warrants), and subject to the PFIC rules discussed below, a U.S. Holder generally will recognize capital gain or loss in an amount equal to the difference between the amount realized and the U.S. Holder’s adjusted tax basis in the ordinary shares or warrants. See “— Exercise or Lapse of a Warrant,” below for a discussion regarding a U.S. Holder’s basis in the ordinary shares acquired pursuant to the exercise of a warrant.

The regular U.S. federal income tax rate on capital gains recognized by U.S. Holders generally is the same as the regular U.S. federal income tax rate on ordinary income, except that long-term capital gains recognized by non-corporate U.S. Holders generally are subject to U.S. federal income tax at a maximum regular rate of 20%. Capital gain or loss will constitute long-term capital gain or loss if the U.S. Holder’s holding period for the ordinary shares or warrants exceeds one year. The deductibility of capital losses is subject to various limitations.

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Additional Taxes

U.S. Holders that are individuals, estates or trusts and whose income exceeds certain thresholds generally will be subject to a 3.8% Medicare contribution tax on unearned income, including, without limitation, dividends on, and gains from the sale or other taxable disposition of, our securities, subject to certain limitations and exceptions. Under recently issued regulations, in the absence of a special election, such unearned income generally would not include income inclusions under the qualified electing fund, or QEF, rules discussed below under “— Passive Foreign Investment Company Rules,” but would include distributions of earnings and profits from a QEF. U.S. Holders should consult their own tax advisors regarding the effect, if any, of such tax on their ownership and disposition of our securities.

Exercise or Lapse of a Warrant

Subject to the PFIC rules discussed below, a U.S. Holder generally will not recognize gain or loss upon the exercise of a warrant for cash. An ordinary share acquired pursuant to the exercise of a warrant for cash generally will have a tax basis equal to the U.S. Holder’s tax basis in the warrant, increased by the amount paid to exercise the warrant. The holding period of such ordinary share generally would begin on the day after the date of exercise of the warrant. If a warrant is allowed to lapse unexercised, a U.S. Holder generally will recognize a capital loss equal to such holder’s tax basis in the warrant.

The tax consequences of a cashless exercise of warrants are not clear under current tax law. A cashless exercise may be tax-free, either because it is not a realization event (i.e., not a transaction in which gain or loss is realized) or because the transaction is treated as a recapitalization for U.S. federal income tax purposes. In either tax-free situation, a U.S. Holder’s tax basis in the ordinary shares received would equal the U.S. Holder’s basis in the warrants. If the cashless exercise were treated as not being a realization event, the U.S. Holder’s holding period in the ordinary shares could be treated as commencing on the date following the date of exercise of the warrants. If the cashless exercise were treated as a recapitalization, the holding period of the ordinary shares received would include the holding period of the warrants.

It is also possible that a cashless exercise could be treated as a taxable exchange in which gain or loss is recognized. In such event, a U.S. Holder could be deemed to have surrendered a number of warrants with a fair market value equal to the exercise price for the number of warrants deemed exercised. For this purpose, the number of warrants deemed exercised would be equal to the number of ordinary shares issued pursuant to the cashless exercise of the warrants. In this situation, the U.S. Holder would recognize capital gain or loss in an amount equal to the difference between the fair market value of the warrants deemed surrendered to pay the exercise price and the U.S. Holder’s tax basis in such warrants deemed surrendered. Such gain or loss would be long-term or short-term depending on the U.S. Holder’s holding period in the warrants. In this case, a U.S. Holder’s tax basis in the ordinary shares received would equal the sum of the fair market value of the warrants deemed surrendered to pay the exercise price and the U.S. Holder’s tax basis in the warrants deemed exercised, and a U.S. Holder’s holding period for the ordinary shares should commence on the date following the date of exercise of the warrants. There also may be alternative characterizations of any such taxable exchange that would result in similar tax consequences, except that a U.S. Holder’s gain or loss would be short-term.

Due to the absence of authority on the U.S. federal income tax treatment of a cashless exercise of warrants it is unclear which, if any, of the alternative tax consequences and holding periods described above would be adopted by the IRS or a court of law. Accordingly, U.S. Holders should consult their tax advisors regarding the tax consequences of a cashless exercise of warrants.

Passive Foreign Investment Company Rules

A foreign (i.e., non-U.S.) corporation will be a PFIC if at least 75% of its gross income in a taxable year of the foreign corporation, including its pro rata share of the gross income of any corporation in which it is considered to own at least 25% of the shares by value, is passive income. Alternatively, a foreign corporation will be a PFIC if at least 50% of its assets in a taxable year of the foreign corporation, ordinarily determined based on fair market value and averaged quarterly over the year, including its pro rata share of the assets of any corporation in which it is considered to own at least 25% of the shares by value, are held for the production of, or produce, passive income. Passive income generally includes dividends, interest, rents and royalties (other than certain rents or royalties derived from the active conduct of a trade or business) and gains from the disposition of passive assets.

Based on the composition (and estimated values and adjusted bases) of the assets and nature of the income of us and our subsidiaries during our 2013 taxable year, we believe that we may be a PFIC for such year. However, because we have not performed a definitive analysis as to our PFIC status for our 2013 taxable year, there can be no assurance in respect to our PFIC status for such year or any future taxable year. We also do not plan to make annual determinations or otherwise notify U.S. Holders of our PFIC status. Accordingly, there can be no assurance with respect to our status as a PFIC for our 2013 taxable year or any future taxable year.

If we are determined to be a PFIC for any taxable year (or portion thereof) that is included in the holding period of a U.S. Holder of our ordinary shares or warrants and, in the case of our ordinary shares, the U.S. Holder did not make either a timely qualified electing fund (“QEF”) election for our first taxable year as a PFIC in which the U.S. Holder held (or was deemed to hold) ordinary shares, a QEF election along with a purging election, or a mark-to-market election, each as described below, such holder generally will be subject to special rules for regular U.S. federal income tax purposes with respect to:

● any gain recognized by the U.S. Holder on the sale or other disposition of its ordinary shares or warrants; and

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●	any “excess distribution” made to the U.S. Holder (generally, any distributions to such U.S. Holder during a taxable year of the U.S. Holder that are greater than 125% of the average annual distributions received by such U.S. Holder in respect of the ordinary shares during the three preceding taxable years of such U.S. Holder or, if shorter, such U.S. Holder’s holding period for the ordinary shares).
Under these rules,
●	the U.S. Holder’s gain or excess distribution will be allocated ratably over the U.S. Holder’s holding period for the ordinary shares or warrants;
●	the amount allocated to the U.S. Holder’s taxable year in which the U.S. Holder recognized the gain or received the excess distribution, or to the period in the U.S. Holder’s holding period before the first day of our first taxable year in which we are a PFIC, will be taxed as ordinary income;
●	the amount allocated to other taxable years (or portions thereof) of the U.S. Holder and included in its holding period will be taxed at the highest tax rate in effect for that year and applicable to the U.S. Holder; and
●	the interest charge generally applicable to underpayments of tax will be imposed in respect of the tax attributable to each such other taxable year of the U.S. Holder.

In general, if we are determined to be a PFIC, a U.S. Holder may avoid the PFIC tax consequences described above in respect to our ordinary shares by making a timely QEF election (or a QEF election along with a purging election). Pursuant to the QEF election, a U.S. Holder will be required to include in income its pro rata share of our net capital gains (as long-term capital gain) and other earnings and profits (as ordinary income), on a current basis, in each case whether or not distributed, in the taxable year of the U.S. Holder in which or with which our taxable year ends. A U.S. Holder may make a separate election to defer the payment of taxes on undistributed income inclusions under the QEF rules, but if deferred, any such taxes will be subject to an interest charge.

A U.S. Holder may not make a QEF election with respect to its warrants. As a result, if a U.S. Holder sells or otherwise disposes of warrants (other than upon exercise of such warrants), any gain recognized generally will be subject to the special tax and interest charge rules treating the gain as an excess distribution, as described above, if we were a PFIC at any time during the period the U.S. Holder held such warrants. If a U.S. Holder that exercises such warrants properly makes a QEF election with respect to the newly acquired ordinary shares (or has previously made a QEF election with respect to our ordinary shares), the QEF election will apply to the newly acquired ordinary shares, but the adverse tax consequences relating to PFIC shares, adjusted to take into account the current income inclusions resulting from the QEF election, will continue to apply with respect to such newly acquired ordinary shares (which generally will be deemed to have a holding period for purposes of the PFIC rules that includes the period the U.S. Holder held the warrants), unless the U.S. Holder makes a purging election with respect to such shares. The purging election creates a deemed sale of such shares at their fair market value. The gain recognized by the purging election will be subject to the special tax and interest charge rules treating the gain as an excess distribution, as described above. As a result of the purging election, the U.S. Holder will increase the adjusted tax basis in its ordinary shares acquired upon exercise of the warrants by the gain recognized and also will have a new holding period in such ordinary shares for purposes of the PFIC rules.

The QEF election is made on a shareholder-by-shareholder basis and, once made, can be revoked only with the consent of the IRS. A U.S. Holder generally makes a QEF election by attaching a completed IRS Form 8621 (Information Return by a Shareholder of a Passive Foreign Investment Company or Qualified Electing Fund), including the information provided in a PFIC annual information statement, to a timely filed U.S. federal income tax return for the taxable year to which the election relates. Retroactive QEF elections generally may be made only by filing a protective statement with such return and if certain other conditions are met or with the consent of the IRS.

In order to comply with the requirements of a QEF election, a U.S. Holder must receive certain information from us. Upon request from a U.S. Holder, we will endeavor to provide to the U.S. Holder no later than 90 days after the request such information as the IRS may require, including a PFIC annual information statement, in order to enable the U.S. Holder to make and maintain a QEF election. However, there is no assurance that we will have timely knowledge of our status as a PFIC in the future or of the required information to be provided.

If a U.S. Holder has made a QEF election with respect to our ordinary shares, and the special tax and interest charge rules do not apply to such shares (because of a timely QEF election for our first taxable year as a PFIC in which the U.S. Holder holds (or is deemed to hold) such shares or a QEF election, along with a purge of the PFIC taint pursuant to a purging election, as described above), any gain recognized on the sale or other taxable disposition of our ordinary shares generally will be taxable as capital gain and no interest charge will be imposed. As discussed above, for regular U.S. federal income tax purposes, U.S. Holders of a QEF are currently taxed on their pro rata shares of the QEF’s earnings and profits, whether or not distributed. In such case, a subsequent distribution of such earnings and profits that were previously included in income generally should not be taxable as a dividend to such U.S. Holders. The adjusted tax basis of a U.S. Holder’s shares in a QEF will be increased by amounts that are included in income, and decreased by amounts distributed but not taxed as dividends, under the above rules. Similar basis adjustments apply to property if by reason of holding such property the U.S. Holder is treated under the applicable attribution rules as owning shares in a QEF.

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Although a determination as to our PFIC status will be made annually, the initial determination that we are a PFIC generally will apply for subsequent years to a U.S. Holder who held ordinary shares or warrants while we were a PFIC, whether or not we meet the test for PFIC status in those subsequent years. A U.S. Holder who makes the QEF election discussed above for our first taxable year as a PFIC in which the U.S. Holder holds (or is deemed to hold) our ordinary shares, however, will not be subject to the PFIC tax and interest charge rules discussed above in respect to such shares. In addition, such U.S. Holder will not be subject to the QEF inclusion regime with respect to such shares for any of our taxable years that end within or with a taxable year of the U.S. Holder and in which we are not a PFIC. On the other hand, if the QEF election is not effective for each of our taxable years in which we are a PFIC and during which the U.S. Holder holds (or is deemed to hold) our ordinary shares, the PFIC rules discussed above will continue to apply to such shares unless the holder files on a timely filed U.S. income tax return (including extensions) a QEF election and a purging election to recognize under the rules of Section 1291 of the Code any gain that the U.S. Holder would otherwise recognize if the U.S. Holder had sold our ordinary shares for their fair market value on the “qualification date.” The qualification date is the first day of our tax year in which we qualify as a QEF with respect to such U.S. Holder. The purging election can only be made if such U.S. Holder held our ordinary shares on the qualification date. The gain recognized by the purging election will be subject to the special tax and interest charge rules treating the gain as an excess distribution, as described above. As a result of the purging election, the U.S. Holder will increase the adjusted tax basis in its ordinary shares by the amount of the gain recognized and will also have a new holding period in the ordinary shares for purposes of the PFIC rules.

Alternatively, if a U.S. Holder, at the close of its taxable year, owns shares in a PFIC that are treated as marketable stock, the U.S. Holder may make a mark-to-market election with respect to such shares for such taxable year. If the U.S. Holder makes a valid mark-to-market election for the first taxable year of the U.S. Holder in which the U.S. Holder holds (or is deemed to hold) our ordinary shares and for which we are determined to be a PFIC, such holder generally will not be subject to the PFIC rules described above in respect to its ordinary shares. Instead, in general, the U.S. Holder will include as ordinary income each year the excess, if any, of the fair market value of its ordinary shares at the end of its taxable year over the adjusted tax basis in its ordinary shares. The U.S. Holder also will be allowed to take an ordinary loss in respect of the excess, if any, of the adjusted tax basis of its ordinary shares over the fair market value of its ordinary shares at the end of its taxable year (but only to the extent of the net amount of previously included income as a result of the mark-to-market election). The U.S. Holder’s adjusted tax basis in its ordinary shares will be adjusted to reflect any such income or loss amounts, and any further gain recognized on a sale or other taxable disposition of the ordinary shares will be treated as ordinary income. Currently, a mark-to-market election may not be made with respect to warrants.

The mark-to-market election is available only for stock that is regularly traded on a national securities exchange that is registered with the Securities and Exchange Commission, or on a foreign exchange or market that the IRS determines has rules sufficient to ensure that the market price represents a legitimate and sound fair market value. Since our ordinary shares are quoted only on the Over-the-Counter Bulletin Board, they may not currently qualify as marketable stock for purposes of the election. U.S. Holders should consult their own tax advisors regarding the availability and tax consequences of a mark-to-market election in respect to our ordinary shares under their particular circumstances.

If we are a PFIC and, at any time, have a foreign subsidiary that is classified as a PFIC, a U.S. Holder generally would be deemed to own a portion of the shares of such lower-tier PFIC, and generally could incur liability for the deferred tax and interest charge described above if we receive a distribution from, or dispose of all or part of our interest in, or the U.S. Holder otherwise were deemed to have disposed of an interest in, the lower-tier PFIC. Upon request, we will endeavor to cause any lower-tier PFIC to provide to a U.S. Holder no later than 90 days after the request the information that may be required to make or maintain a QEF election with respect to the lower-tier PFIC. However, there is no assurance that we will have timely knowledge of the status of any such lower-tier PFIC, and we do not plan to make annual determinations or otherwise notify U.S. Holders of the PFIC status of any such lower-tier PFIC.  There also is no assurance that we will be able to cause the lower-tier PFIC to provide the required information. U.S. Holders are urged to consult their own tax advisors regarding the tax issues raised by lower-tier PFICs.

A U.S. Holder that owns (or is deemed to own) shares in a PFIC during any taxable year of the U.S. Holder generally may have to file an IRS Form 8621 (whether or not a QEF election or mark-to-market election is or has been made) with such U.S. Holder’s U.S. federal income tax return and provide such other information as may be required by the U.S. Treasury Department.

The rules dealing with PFICs and with the QEF and mark-to-market elections are very complex and are affected by various factors in addition to those described above. Accordingly, U.S. Holders of our securities should consult their own tax advisors concerning the application of the PFIC rules to our securities under their particular circumstances.

Non-U.S. Holders

Dividends (including constructive dividends) paid or deemed paid to a Non-U.S. Holder in respect to our securities generally will not be subject to U.S. federal income tax, unless the dividends are effectively connected with the Non-U.S. Holder’s conduct of a trade or business within the United States (and, if required by an applicable income tax treaty, are attributable to a permanent establishment or fixed base that such holder maintains or maintained in the United States).

In addition, a Non-U.S. Holder generally will not be subject to U.S. federal income tax on any gain attributable to a sale or other taxable disposition of our securities unless such gain is effectively connected with its conduct of a trade or business in the United States (and, if required by an applicable income tax treaty, is attributable to a permanent establishment or fixed base that such holder maintains or maintained in the United States) or the Non-U.S. Holder is an individual who is present in the United States for 183 days or more in the taxable year of sale or other disposition and certain other conditions are met (in which case, such gain from U.S. sources generally is subject to U.S. federal income tax at a 30% rate or a lower applicable tax treaty rate).

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Dividends and gains that are effectively connected with the Non-U.S. Holder’s conduct of a trade or business in the United States (and, if required by an applicable income tax treaty, are attributable to a permanent establishment or fixed base that such holder maintains or maintained in the United States) generally will be subject to regular U.S. federal income tax at the same regular U.S. federal income tax rates applicable to a comparable U.S. Holder and, in the case of a Non-U.S. Holder that is a corporation for U.S. federal income tax purposes, may also be subject to an additional branch profits tax at a 30% rate or a lower applicable tax treaty rate.

The U.S. federal income tax treatment of a Non-U.S. Holder’s exercise of a warrant, or the lapse of a warrant held by a Non-U.S. Holder, generally will correspond to the U.S. federal income tax treatment of the exercise or lapse of a warrant by a U.S. Holder, as described under “U.S. Holders — Exercise or Lapse of a Warrant,” above.

Backup Withholding and Information Reporting

In general, information reporting for U.S. federal income tax purposes should apply to distributions made on our securities within the United States to a U.S. Holder (other than an exempt recipient) and to the proceeds from sales and other dispositions of our securities by a U.S. Holder (other than an exempt recipient) to or through a U.S. office of a broker. Payments made (and sales and other dispositions effected at an office) outside the United States will be subject to information reporting in limited circumstances. In addition, certain information concerning a U.S. Holder’s adjusted tax basis in its securities and adjustments to that tax basis and whether any gain or loss with respect to such securities is long-term or short-term also may be required to be reported to the IRS, and certain holders may be required to file an IRS Form 8938 (Statement of Specified Foreign Financial Assets) to report their interest in our securities.

Moreover, backup withholding of U.S. federal income tax at a rate of 28% generally will apply to dividends paid on our securities to a U.S. Holder (other than an exempt recipient) and the proceeds from sales and other dispositions of our securities by a U.S. Holder (other than an exempt recipient), in each case who (a) fails to provide an accurate taxpayer identification number; (b) is notified by the IRS that backup withholding is required; or (c) in certain circumstances, fails to comply with applicable certification requirements.

A Non-U.S. Holder generally may eliminate the requirement for information reporting and backup withholding by providing certification of its foreign status, under penalties of perjury, on a duly executed applicable IRS Form W-8 or by otherwise establishing an exemption.

Backup withholding is not an additional tax. Rather, the amount of any backup withholding will be allowed as a credit against a U.S. Holder’s or a Non-U.S. Holder’s U.S. federal income tax liability and may entitle such holder to a refund, provided that certain required information is timely furnished to the IRS. Holders are urged to consult their own tax advisors regarding the application of backup withholding and the availability of and procedures for obtaining an exemption from backup withholding in their particular circumstances.

F.             Dividends and paying agents

On April 3, 2013, we announced the authorization of a previously announced one-time cash dividend of $0.10 per outstanding ordinary share. The dividend was paid on April 25, 2013.

On October 4, 2013, we announced the authorization of a previously announced one-time cash dividend of $0.10 per outstanding ordinary share. The dividend was paid on October 24, 2013.

We do not anticipate paying any additional cash dividends on its ordinary shares in the foreseeable future. We currently intend to retain future earnings, if any, to finance the expansion of our business. Our future dividend policy is within the discretion of our board of directors and will depend upon various factors, including our business, financial condition, results of operations, capital requirements and investment opportunities.

G.      Statement by experts

Not required.

H.      Documents on display

Documents concerning us that are referred to in this document may be inspected at our principal executive offices at 500 W. Texas Avenue, Suite 1450, Midland, Texas 79701.

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In addition, we will file annual reports and other information with the Securities and Exchange Commission. We will file annual reports on Form 20-F and submit other information under cover of Form 6-K. As a foreign private issuer, we are exempt from the proxy requirements of Section 14 of the Exchange Act and our officers, directors and principal shareholders will be exempt from the insider short-swing disclosure and profit recovery rules of Section 16 of the Exchange Act. Annual reports and other information we file with the Commission may be inspected at the public reference facilities maintained by the Commission at Room 1024, 100 F. Street, N.E., Washington, D.C. 20549, and at its regional offices located at 233 Broadway, New York, New York 10279 and 500 West Madison Street, Suite 1400, Chicago, Illinois 60661, and copies of all or any part thereof may be obtained from such offices upon payment of the prescribed fees. You may call the Commission at 1-800-SEC-0330 for further information on the operation of the public reference rooms and you can request copies of the documents upon payment of a duplicating fee, by writing to the Commission. In addition, the Commission maintains a web site that contains reports and other information regarding registrants (including us) that file electronically with the Commission which can be accessed at http://www.sec.gov.

I.        Subsidiary Information

Not required.

ITEM 11. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK

Quantitative and Qualitative Disclosures about Market Risk

We place temporary cash investments with financial institutions and invest in those institutions and instruments that our management believes have minimal credit risk and market risk.

ITEM 12. DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES

Not required.

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PART II

ITEM 13. DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES

There has been no default of any indebtedness nor is there any arrearage in the payment of dividends.

ITEM 14. MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS

A.            Use of Proceeds

On March 24, 2011, we completed (i) our IPO of 4,000,000 units and (ii) the Warrant Offering of 6,600,000 warrants. On March 29, 2011, the underwriters of our IPO exercised their over-allotment option, for a total of an additional 106,500 units (over and above the 4,000,000 units sold in our IPO) for an aggregate offering of 4,106,500 units. Each unit consists of one ordinary share and one warrant.  Each warrant entitles the holder to purchase one ordinary share at a price of $5.00.  The units were sold at an offering price of $8.00 per unit and the warrants were sold at an offering price of $0.35 per warrant, generating total gross proceeds of $34,310,000.  EarlyBirdCapital, Inc. (“EBC”) acted as the underwriter. The securities sold in the IPO were registered under the Securities Act of 1933 on a registration statement on Form F-1 (File No. 333-172334). The Securities and Exchange Commission declared the registration statement effective on March 16, 2011.

We incurred a total of $1,149,820 in underwriting discounts and commissions. The total expenses in connection with the sale of our warrants in the Warrant Offering and the IPO (including the underwriter’s discounts and commissions) were $1,463,586.

After deducting the underwriting discounts and commissions and the offering expenses, the total net proceeds to us from the Warrant Offering and the IPO were $33,698,414. $33,462,180 (or approximately $8.15 per unit sold in our IPO) of the net proceeds from the IPO and the Warrant Offering was placed in a trust account for our benefit and the remaining proceeds are available to be used to provide for business, legal and accounting due diligence on prospective business combinations and continuing general and administrative expenses. The amounts held in the trust account may only be used by us upon the consummation of a business combination, except that there can be released to us, from time to time, (i) amounts necessary to purchase up to 50% of the shares sold in our IPO, (ii) any interest earned on the funds in the trust account that we may need to pay our tax obligations and (iii) any remaining interest earned on the funds in the trust account that we need for our working capital requirements. The remaining interest earned on the funds in the trust account will not be released until the earlier of the completion of a business combination and our liquidation upon failure to effect a business combination within the allotted time.

Through December 24, 2013, we had used $5,189,108 of the proceeds from our IPO and Warrant Offering to repurchase 665,000 ordinary shares in accordance with our 10b5-1 repurchase plan and $22,701,424 to redeem outstanding ordinary shares in connection with our three tender offers.  We have incurred $1,120,000 in investment banking fees, $120,681 in travel and entertainment expenses, $251,250 in rent expenses, $246,764 in insurance expenses, $486,926 in legal expenses and $375,395 in general and administrative expenses since the closing of the IPO.  The balance of the proceeds from our IPO and Warrant Offering were transferred to Arabella upon the close of the Acquisition.

ITEM 15. CONTROLS AND PROCEDURES

A.           Disclosure Controls and Procedures

An evaluation of the effectiveness of our disclosure controls and procedures as of December 31, 2013 was made under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer. Based on that evaluation, our Chief Executive Officer concluded that our disclosure controls and procedures are effective as of the end of the period covered by this report.

Disclosure controls and procedures are designed to ensure that information required to be disclosed by us in reports that we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms.

B.           Management’s Annual Report on Internal Control Over Financial Reporting

Our internal control over financial reporting is a process designed by, or under the supervision of, our Chief Executive Officer and Chief Financial Officer and effected by our board of directors to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of our financial statements for external reporting purposes in accordance with generally accepted accounting principles. Internal control over financial reporting includes policies and procedures that pertain to the maintenance of records that in reasonable detail accurately reflect the transactions and dispositions of our assets; provide reasonable assurance that transactions are recorded as necessary to permit preparation of our financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with the authorization of our board of directors and management; and provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on our financial statements.

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Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation under the criteria established in Internal Control – Integrated Framework, our management concluded that our internal control over financial reporting was effective as of December 31, 2013.

E.            Attestation Report of the Registered Public Accounting Firm

Not required.

D.           Changes in Internal Controls over Financial Reporting

There were no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) of the Exchange Act) that occurred during the year ended December 31, 2013 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

ITEM 16. [RESERVED]

ITEM 16A. AUDIT COMMITTEE FINANCIAL EXPERT.

The audit committee currently consists of William B. Heyn.  Additional members are expected to be appointed in the near future.

ITEM 16B. CODE OF ETHICS.

We have not yet adopted a code of ethics.

ITEM 16C. PRINCIPAL ACCOUNTANT FEES AND SERVICES.

The following table sets forth the aggregate fees by categories specified below in connection with certain professional services rendered by Marcum LLP, our principal external independent registered public accounting firm, for the periods indicated.

	2013		2012
Audit fees(1)	$	80,000	$	18,500
Audit related fees		12,000		--
Tax fees		--		--
Total fees	$	92,000	$	18,500

(1) “Audit fees” means the aggregate fees billed for an audit of our consolidated financial statements and our internal control over financial reporting.

Our board of directors is to pre-approve all auditing services and permitted non- audit services to be performed for us by our independent auditor, including the fees and terms thereof (subject to the de minimums exceptions for non-audit services described in section 10A(i)(1)(B) of the Exchange Act which are approved by the audit committee or our board of directors prior to the completion of the audit).

ITEM 16D. EXEMPTIONS FROM THE LISTING STANDARDS FOR AUDIT COMMITTEES.

None.

ITEM 16E. PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PURCHASERS.

None.

ITEM 16F. CHANGES IN REGISTRANT’S CERTIFYING ACCOUNTANT.

Not applicable.

ITEM 16G. CORPORATE GOVERNANCE

Not applicable.

57

PART III

ITEM 17. FINANCIAL STATEMENTS

We have elected to provide financial statements pursuant to Item 18.

ITEM 18. FINANCIAL STATEMENTS

The financial statements are filed as part of this annual report beginning on page F-1.

ITEM 19. EXHIBITS

Exhibit No.	Description
1.1	Amended and Restated Memorandum and Articles of Association*
2.1	Specimen Unit Certificate*
2.2	Specimen Ordinary Share Certificate*
2.3	Specimen Warrant Certificate*
2.4	Form of Unit Purchase Option*
4.1	Form of Underwriting Agreement*
4.2	Form of Warrant Agreement between Continental Stock Transfer & Trust Company and the Registrant*
4.3	Form of Representative’s Unit Purchase Option*
4.4	Form of Letter Agreement among the Registrant, EarlyBirdCapital, Inc. and each of the Initial Shareholders*
4.5	Form of Investment Management Trust Agreement between Continental Stock Transfer & Trust Company and the Registrant*
4.6	Form of Share Escrow Agreement between the Registrant, Continental Stock Transfer & Trust Company and the Initial Shareholders*
4.7	Form of Registration Rights Agreement among the Registrant and the Initial Shareholders*
4.8	Form of Warrant Purchase Agreement among the Registrant, Loeb & Loeb LLP and each of the Initial Shareholders*
4.9	Letter Agreement between BBS Capital Fund, LP, Rampant Dragon, LLC and the Registrant regarding administrative support*
4.10	10b5-1 Trading Plan between the Registrant and Morgan Stanley Smith Barney, LLC*
10.1	Agreement and Plan of Merger and Reorganization dated October 23, 2013 by and among Lone Oak Acquisition Corporation, a Cayman Islands company, Arabella Exploration Corp., a Delaware corporation, Arabella Exploration, LLC, a Texas limited liability company, and each of the stockholders set forth on Schedule I thereto**
10.2	Voting Agreement among the Registrant and the signatories thereto***
10.3	Registration Rights Agreement dated December 24, 2013***
10.4	Employment Agreement of Jason Hoisager dated December 24, 2013***
10.5	Lock-Up Agreement dated December 24, 2013***
12.1	Certification of the Chief Executive Officer (Principal Executive Officer) pursuant to Rule 13a-14(a) of the Securities Exchange Act, as amended.
12.2	Certification of the Chief Financial Officer (Principal Financial Officer) pursuant to Rule 13a-14(a) of the Securities Exchange Act, as amended
13.1	Certification of the Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101	Interactive Data Files

* Incorporated by reference to the Registrant’s Registration Statement on Form F-1 (Commission File No. 333-172334).

** Incorporated by reference to the Report of Foreign Private Issuer dated October 25, 2013.

*** Incorporated by reference to the Form 20-F filed on December 31, 2013.

58

SIGNATURES

The Registrant hereby certifies that it meets all of the requirements for filing on Form 20-F and that it has duly caused and authorized the undersigned to sign this annual report on its behalf.

	ARABELLA EXPLORATION, INC.
May 15, 2014	By:	/s/ Jason Hoisager
	Name:	Jason Hoisager
	Title:	Chief Executive Officer

59

ARABELLA EXPLORATION, INC.

CONSOLIDATED FINANCIAL STATEMENTS

WITH REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMS

December 31, 2013, 2012 and 2011

F-1

ARABELLA EXPLORATION, INC.

TABLE OF CONTENTS

	Page
Report of Independent Registered Public Accounting Firms	F-3
Consolidated Financial Statements:
Consolidated Balance Sheets	F-5
Consolidated Statements of Operations	F-6
Consolidated Statements of Shareholders’ Equity	F-7
Consolidated Statements of Cash Flows	F-8
Notes to Consolidated Financial Statements	F-9 - F-22

F-2

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Audit Committee of the

Board of Directors and Shareholders

of Arabella Exploration, Inc.

We have audited the accompanying consolidated balance sheet of Arabella Exploration, Inc. and its Subsidiary (collectively the “Company”) as of December 31, 2013, and the related consolidated statements of operations, changes in shareholders’ equity and cash flows for the year then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit.

We conducted our audit 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 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. Our audit included 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 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 audit provides a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Arabella Exploration, Inc. and its Subsidiary, as of December 31, 2013, and the results of their operations and their cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America.

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern.  As discussed in Note 4 to the accompanying consolidated financial statements, the Company has a working capital deficit of $1,240,656, and a substantial portion of the Company’s oil and natural gas properties are undeveloped as of December 31, 2013.  The Company’s ability to continue as a going concern is dependent on its ability to develop its oil and natural gas properties and to achieve profitable operations and to generate sufficient cash flow to meet its obligations as they become due.  The Company will need to raise additional capital through debt or equity offerings in order to implement its oil and natural gas properties development plan and to support higher costs and expense in 2014.  There can be no assurance that the Company can raise capital through additional debt or equity offerings on commercially acceptable terms if at all.  These conditions raise substantial doubt about the Company’s ability to continue as a going concern.  Management’s plans are discussed in Note 4 to the accompanying consolidated financial statements

Marcum llp

New York, NY

May 15, 2014

F-3

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders

of Arabella Exploration, Inc.:

We have audited the accompanying consolidated balance sheet of Arabella Exploration, Inc. (the Company) as of December 31, 2012, and the related consolidated statements of operations and member’s equity, and cash flows for the two years in the period 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 financial statements are free of material misstatement.  An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the 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 Arabella Exploration, Inc. as of December 31, 2012 and the results of its operations and its cash flows for the two years in the period then ended, in conformity with U.S. generally accepted accounting principles.

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As shown in the consolidated financial statements and discussed in Note 4, the Company has incurred recurring losses from operations and is dependent on outside sources of financing for continuation of its operations. These and other factors raise substantial doubt about the Company’s ability to continue as a going concern. Management’s plans with regard to this matter are also discussed in Note 4. These consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

/s/ Ham, Langston & Brezina, LLP

Houston, Texas

October 18, 2013, except for notes 1, 2, 4, 6, 7 and 8,

as to which the date is December 12, 2013

Ham, Langston & Brezina L.L.P. | 11550 Fuqua, Suite 475, Houston, TX 77034 | 281-481-1040 | www.hlb-cpa.com

F-4

ARABELLA EXPLORATION, INC.

CONSOLIDATED BALANCE SHEETS

DECEMBER 31, 2013 AND 2012

	2013		2012
ASSETS
Current assets:
Cash and cash equivalents	$	2,118,533	$	12,990
Accounts receivable - oil and gas sales		436,830		7,588
Prepaid expenses		23,077		—
Total current assets		2,578,440		20,578
Deposits		25,000		—
Prepaid drilling costs to Arabella Petroleum Company, LLC		—		219,495
Oil and gas properties, successful efforts method - Net		13,249,367		1,516,236
Total assets	$	15,852,807	$	1,756,309
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	84,691	$	20,000
Accrued joint interest billings payable		3,734,405		42,238
Total current liabilities		3,819,096		62,238
Note payable to officer		3,007,170		1,242,696
Asset retirement obligations		21,171		2,963
Total liabilities		6,847,437		1,307,897
Commitments and contingencies
Shareholders’ equity
Preferred shares, $0.001 par value, authorized 5,000,000 shares and none issued and outstanding		—		—
Ordinary shares, $0.001 par value, authorized 50,000,000 shares;  issued and outstanding 4,829,826 at December 31, 2013, and 3,125,000 at December 31, 2012		4,830		3,125
Additional paid-in-capital		8,488,970		125,436
Retained earnings		511,570		319,851
Total shareholders’ equity		9,005,370		448,412
Total liabilities and shareholders’ equity	$	15,852,807	$	1,756,309

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

F-5

ARABELLA EXPLORATION, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

FOR THE YEARS ENDED DECEMBER 31, 2013, 2012 AND 2011

	2013		2012		2011
Revenues:
Oil and gas revenue	$	1,421,915	$	65,881	$	16,543
Other operating revenue – gain on sale of oil and gas properties		—		402,901		34,467
Total revenues		1,421,915		468,782		51,010
Costs and expenses:
Lease operating expenses		152,052		12,526		5,753
Ad valorem and production taxes		64,033		3,174		819
Depreciation, depletion and amortization		469,230		27,696		5,724
Accretion of asset retirement obligation		663		215		97
General and administrative expenses		412,268		10,010		10,011
General and administrative expenses allocated from Arabella Petroleum Company, LLC		131,950		93,845		30,071
Total costs and expenses		1,230,196		147,466		52,475
Net income (loss)	$	191,719	$	321,316	$	(1,465	)
Net income (loss) per ordinary share:
Basic	$	0.06	$	0.10	$	(0.00	)
Diluted	$	0.06	$	0.10	$	(0.00	)
Weighted average ordinary shares outstanding:
Basic		3,157,695		3,125,000		3,125,000
Diluted		3,201,305		3,125,000		3,125,000

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

F-6

ARABELLA EXPLORATION, INC.

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

FOR THE YEARS ENDED DECEMBER 31, 2013, 2012 AND 2011

	Ordinary				Paid-In		Retained
	Shares				Capital		Earnings			Total
	Shares		Amount			—
Balance at December 31, 2010		—	$	—	$		$	—		$	—
Shares effectively issued to founder		3,125,000		3,125		26,876		—			30,001
Net loss		—		—		—		(1,465	)		(1,465	)
Balance at December 31, 2011		3,125,000		3,125		26,876		(1,465	)		28,536
Contribution by founder		—		—		98,560		—			98,560
Net income		—		—		—		321,316			321,316
Balance at December 31, 2012		3,125,000		3,125		125,436		319,851			448,412
Contributions by founder:
Cash		—		—		40,000		—			40,000
General and administrative expenses		—		—		131,950		—			131,950
Oil and gas assets		—		—		3,009,832		—			3,009,832
Outstanding shares of Lone Oak    Acquisition Corporation at the time    of the time of the reverse merger		1,704,826		1,705		5,181,752		—			5,183,457
Net income		—		—		—		191,719			191,719
Balance at December 31, 2013		4,829,826	$	4,830	$	8,488,970	$	511,570		$	9,005,370

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

F-7

ARABELLA EXPLORATION, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

FOR THE YEARS ENDED DECEMBER 31, 2013, 2012 AND 2011

	2013			2012			2011
Cash flows from operating activities:
Net income (loss)	$	191,719		$	321,316		$	(1,465	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		469,230			27,696			5,724
Accretion of asset retirement obligation		663			215			97
Contribution recognized for allocated general and administrative expenses		131,950			93,845			30,071
Gain from sale of oil and gas properties		—			(402,901	)		(34,467	)
Changes in operating assets and liabilities:
Accounts receivable - oil and gas sales		(429,242	)		(2,621	)		(4,967	)
Prepaid expenses		(23,077	)		—			—
Deposits		(25,000	)		—			—
Accounts payable and accrued liabilities		64,691			50,986			11,252
Net cash provided by operating activities		380,934			88,536			6,245
Cash flows from investing activities:
Additions to oil and gas properties		(3,718,303	)		(526,642	)		(68,771	)
Proceeds from sale of oil and gas properties		—			592,702			34,667
Prepaid drilling costs		219,495			(155,177	)		(64,318	)
Net cash used in investing activities		(3,498,808	)		(89,117	)		(98,422	)
Cash flows from financing activities:
Cash received in merger		5,183,417			—			—
Cash contribution from shareholder		40,000			—			—
Proceeds from shareholders loans		—			74,942			92,192
Repayment of shareholder loans		—			(61,386	)		—
Net cash provided by financing activities		5,223,417			13,556			92,192
Net increase in cash and cash equivalents		2,105,543			12,975			15
Cash and cash equivalents at beginning of year		12,990			15			—
Cash and cash equivalents at end of year	$	2,118,533		$	12,990		$	15
Non-cash investing and financing activities:
Addition to oil and gas properties through increase in accrued joint interest billings payable	$	3,692,167		$	1,087,987		$	62,077
Addition to oil and gas properties through Increase in Notes payable to officer	$	1,764,474		$	—		$	—
Addition to oil and gas properties contributed by officer	$	3,009,832
Capitalized imputed interest expense contributed by sole member related to member loans	$	2,662		$	4,715		$	370
Increase in oil and gas properties through recognition of asset retirement obligation	$	18,208		$	2,638		$	2,699

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

F-8

1. Organization and Operations of the Company

Organization

Arabella Exploration, Inc. (formerly known as Lone Oak Acquisition Corporation) (the “Parent”) was incorporated in the Cayman Islands on June 17, 2010 as a blank check company whose objective was to acquire and operating business.  Parent’s wholly owned subsidiary Arabella Exploration LLC (“Arabella LLC”) was formed in 2011, to acquire interests in low risk prospective or currently producing oil and gas properties primarily in the Texas Permian Basin.  The Parent and Arabella LLC (collectively the “Company”) completed a reverse merger on December 24, 2013 as more fully described below in Note 3.

Nature of Business

The Company is an independent exploration and production company focused on the acquisition and development of unconventional oil and natural gas resources in the Permian Basin in West Texas. The Company owns acreage leases and participates in the drilling of oil and natural gas wells with other working interest partners. Due to the capital intensive nature of oil and natural gas drilling activities, the operating company responsible for conducting the drilling operations may request advance payments from the working interest partners for their share of the costs.

2. Initial Orginization and Public Offering

In connection with the organization of the Parent a total of 1,150,000 shares of the Parents’s ordinary shares were sold to its founding shareholders at a price of $0.0217 per share for an aggregate of $25,000.

The Parent consummated its initial public offering (the “Offering”) on March 24, 2011 and received proceeds net of transaction costs of $30,566,234 and $2,310,000 from the private placement of warrants to certain of the members of management of the Parent (the "Insider Warrants"). On March 30, 2011 the over-allotment option was partially exercised and the Parent received an additional $822,180 net of transaction costs. A total of 4,106,500 units consisting of one ordinary share and one warrant each were sold in the offering and exercise of the over-allotment option. The number of ordinary shares held by the founding shareholders was subject to forfeiture by such shareholders if the over-allotment option was not exercised in full by the underwriters of the Offering.  After the partial exercise and expiration of the over-allotment option 123,375 of the shares held by the founding shareholders were forfeited. An amount of $33,462,180 (including the $2,310,000 of proceeds from the sale of Insider Warrants) was placed in a trust account (“Trust”) until the earlier of (i) the consummation of the Parent’s first Business Combination, (ii) the Company’s failure to consummate a Business Combination within the prescribed time and (iii) the Common Stock trades at or below $7.75 per share, subject to certain criteria contained in the 10b5-1 plan, prior to the announcement of a Business Combination. A Business Combination was announced on September 19, 2012, terminating the 10b5-1 plan. As of that date, a total of 665,000 shares had been repurchased under the 10b5-1 plan at a total cost, including expenses, of $5,189,108.

On February 25, 2013, the Parent commenced a tender offer (the “First Tender Offer”) for up to 2,829,535 of its ordinary shares at approximately $8.22 per share (the amount held in trust per share). The First Tender Offer expired on March 22, 2013. A total of 2,303,899 ordinary shares had been tendered representing $18,927,300. The funds were released from the Trust and paid to tendering shareholders on March 28, 2013. The tendered shares were canceled. Following the payment and cancelation of the tendered shares, 2,164,226 of the Parent’s ordinary shares remained outstanding and $9,345,772 remained in the Trust. On August 21, 2013, the Parent commenced a tender offer (the “Second Tender Offer”) for up to 525,636 of its ordinary shares at approximately $8.22 per share (the amount held in trust per share). The Second Tender Offer expired on September 19, 2013. A total of 20,000 ordinary shares had been tendered representing $164,307. The funds were released from the Trust and paid to tendering shareholders on September 24, 2013. The tendered shares were canceled. Following the payment and cancelation of the tendered shares, 2,144,226 of the Parent’s ordinary shares remained outstanding and $9,181,466 remained in the Trust.

In connection with the reverse merger more fully described in Note 3 below, on October 25, 2013 the Parent commenced a tender offer (the “Third Tender Offer”) for up to 505,636 of its ordinary shares at approximately $8.22 per share (the amount held in trust per share). The Third Tender Offer ultimately expired on December 24, 2013.  A total of 439,400 ordinary shares had been tendered representing $3,609,818.  The funds were released from the Trust and paid to tendering shareholders on December 27, 2013. The tendered shares were canceled. Following the payment and cancelation of the tendered shares, 1,704,826 of the Parent’s ordinary shares remained outstanding and the remaining funds in the Trust in the amount of $5,183,417 were distributed to the Parent.

F-9

3. Reverse Merger

Parent and Arabella LLC (the wholly owned subsidiary) entered into a reverse merger on December 24, 2013 where the Parent issued 3,125,00 ordinary shares to the holders of all of the issued and outstanding interests of Arabella LLC immediately prior to the time of the Acquisition in exchange for 100% of the units of Arabella LLC. With that exchange, Mr. Hoisager owns the majority of the Company’s ordinary shares.

In connection with the reverse merger, 1,705,002 of additional ordinary shares (“earnout shares”) will be awarded to individuals associated with Arabella LLC over the following three years, if and when the Company achieves the following goals:

● One third of the earnout shares will be awarded if the proved reserves of the Company as of December 31, 2014 shall have increased 100% from the proved reserves as of the closing date of the reverse merger if (a) the finding and development cost per proved barrel of oil equivalent (“BOE”) of the increase in proved reserves is $22 or less and/or if the ratio of finding and development cost to BOE is superior (lower per BOE) or equal to 80% of the public peer set, and (b) the Company’s general and administrative cost per BOE of the increase in proved reserves is $12.50 or less and/or if the Company’s general and administrative cost per BOE of the increase is superior (lower per BOE) or equal to 80% of the public peer set (as specified in the agreement and plan of merger).

● One third of the earnout shares will be awarded if the proved reserves of the Company as of December 31, 2015 shall have increased 66% from the proved reserves as of December 31, 2014 if (a) the finding and development cost per proved barrel of oil equivalent (“BOE”) of the increase in proved reserves is $18 or less and/or if the ratio of finding and development cost to BOE is superior (lower per BOE) or equal to 80% of the public peer set, and (b) the Company’s general and administrative cost per BOE of the increase in proved reserves is $6.50 or less and/or if the Company’s general and administrative cost per BOE of the increase is superior (lower per BOE) or equal to 80% of the public peer set.

● One third of the earnout shares will be awarded if the proved reserves of the Company as of December 31, 2016 shall have increased 33% from the proved reserves as of December 31, 2015 if (a) the finding and development cost per proved barrel of oil equivalent (“BOE”) of the increase in proved reserves is $14 or less and/or if the ratio of finding and development cost to BOE is superior (lower per BOE) or equal to 80% of the public peer set, and (b) the Company’s general and administrative cost per BOE of the increase in proved reserves is $5.00 or less and/or if the Company’s general and administrative cost per BOE of the increase is superior (lower per BOE) or equal to 80% of the public peer set.

The merger will be accounted for as a “reverse merger” and recapitalization since the shareholders of Arabella LLC (i) owned a majority of the outstanding ordinary shares of the Company immediately following the completion of the transaction, and (ii) have the significant influence and the ability to elect or appoint or to remove a majority of the members of the governing body of the combined entity, and Arabella LLC’s senior management dominates the management of the combined entity ifollowing the completion of the transaction in accordance with the provision of Financial Accounting Standards Board Accounting Standards Codification (“FASB-ASC”) topic 805 Business Combinations. Accordingly, Arabella LLC will be deemed to be the accounting acquirer in the transaction and, consequently, the transaction is treated as a recapitalization of Arabella LLC. Accordingly, the assets and liabilities and the historical operations that are reflected in the financial statements are those of Arabella LLC and are recorded at the historical cost basis of Arabella LLC. Parent’s assets, liabilities and results of operations were consolidated with the assets, liabilities and results of operations of Arabella LLC after consummation of the acquisition.

4. Ability to Continue As a Going Concern

The accompanying financial statements have been prepared in US dollars and in accordance with accounting principles generally accepted in the United States on a going concern basis, which contemplates the realization of assets and the satisfaction of liabilities and commitments in the normal course of business.  The Company commenced its oil and gas exploration activities in 2011. During the year ended December 31, 2013, the Company’s oil and gas properties increased $ 12.2 million in costs. In addition, the Company had a working capital deficit of $ 1,240,656 at December 31, 2013, and has not raised additional debt or equity to drill additional wells and support higher costs and expenses in 2014. These conditions raise substantial doubt about the Company’s ability to continue as a going concern.

F-10

 The Company’s ability to continue as a going concern is dependent on its ability to develop its oil and gas properties and achieve profitable operations and to generate sufficient cash flow from financing and operations to meet its obligations as they become payable. The Company expects that it will need approximately $ 40 million to fund its operations during the next twelve months, which will include minimum annual property lease payments, well expenditures and operating costs and expenses.

Management has plans to seek additional capital through private debt for the development of its oil and gas properties and operating costs and expenses. Although there are no assurances that management’s plans will be realized, or that such debt can be obtain on terms reasonable to the Company, management believes that the Company will be able to continue operations in the future.  In the event that said funds are not available or acceptable, the Company will consider alternative financing structures and/or slow its exploration activities.  Accordingly, no adjustment relating to the recoverability and classification of recorded asset amounts and the classification of liabilities has been made to the accompanying financial statements in anticipation of the Company not being able to continue as a going concern.

5. Summary of Significant Accounting Policies

Basis of Presentation

The accompanying consolidated financial statements of the Company include the accounts of Arabella Exploration Inc. and its wholly owned subsidiary Arabella Exploration LLC. These statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). All significant intercompany transactions have been eliminated in consolidation. Certain reclassifications of prior year balances have been made to conform such amounts to current year classifications in accordance with the reverse merger. The Consolidated Statement of Operations includes the operations of Arabella Exploration LLC to the date of the reverse merger. Subsequent to the reverse merger, the operations also includes the operations of the Parent.

Use of Estimates

Preparation of the Company’s consolidated financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to proved oil and natural gas reserves and related cash flow estimates used in impairment tests of long-lived assets, estimates of future development, dismantlement and abandonment costs, estimates relating to certain oil and natural gas revenues and expenses and estimates of expenses related to legal, environmental and other contingencies. Certain of these estimates require assumptions regarding future commodity prices, future costs and expenses and future production rates. Actual results could differ from those estimates.

As an oil and natural gas producer, the Company’s revenue, profitability and future growth are substantially dependent upon the prevailing and future prices for oil and natural gas, which are dependent upon numerous factors beyond its control such as economic, political and regulatory developments and competition from other energy sources. The energy markets have historically been very volatile and there can be no assurance that oil and natural gas prices will not be subject to wide fluctuations in the future. A substantial or extended decline in oil and natural gas prices could have a material adverse effect on the Company’s financial position, results of operations, cash flows and quantities of oil and natural gas reserves that may be economically produced.

Estimates of oil and natural gas reserves and their values, future production rates and future costs and expenses are inherently uncertain for numerous reasons, including many factors beyond the Company’s control. Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of data available and of engineering and geological interpretation and judgment. In addition, estimates of reserves may be revised based on actual production, results of subsequent exploration and development activities, prevailing commodity prices, operating costs and other factors. These revisions may be material and could materially affect future depreciation, depletion and amortization expense, dismantlement and abandonment costs, and impairment expense.

F-11

Cash and Cash Equivalents

The Company considers all highly liquid investments purchased with a maturity of three months or less when purchased and money market funds to be cash equivalents. The Company maintains cash and cash equivalents in bank deposit accounts which, at times, may exceed the federally insured limits. The Company has not experienced any significant losses from such investments.

Accounts Receivable

Accounts receivable consist of receivables from the operators for properties in which the Company has working interest for the oil and natural gas production delivered to purchasers. The purchasers remit payment for production directly to the operator, then the operator allocates the revenue based on the working interest of the owners.  The Company generally receives its share of the working interest revenue within three months after the production month.

Accounts receivable are stated at amounts based on the percent revenue working interest due from the purchasers that goes through the operator of the property, net of an allowance for doubtful accounts when the Company believes collection is doubtful.  Accounts receivable outstanding longer than the contractual payment terms are considered past due. The Company determines its allowance by considering a number of factors, including the length of time accounts receivable are past due, the Company’s previous loss history, the condition of the general economy and the industry as a whole. The Company writes off specific accounts receivable when they become uncollectible, and payments subsequently received on such receivables are credited to the allowance for doubtful accounts. No allowance was deemed necessary at December 31, 2013 or December 31, 2012.

Oil and Gas Properties

Proved Oil and Gas Properties

Oil and natural gas exploration and development activities are accounted for using the successful efforts method. Under this method, all property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending determination of whether the well has found proved reserves. If an exploratory well does not find proved reserves, the costs of drilling the well are charged to expense. The costs of development wells are capitalized whether productive or nonproductive.

The provision for depreciation, depletion and amortization (“DD&A”) of oil and natural gas properties is calculated on a field-by-field basis using the unit-of-production method. All capitalized well costs and leasehold costs of proved properties are amortized on a unit-of-production basis over the remaining life of proved developed reserves and total proved reserves, respectively. The calculation for the unit-of-production DD&A method takes into consideration estimated future dismantlement, restoration and abandonment costs, which are net of estimated salvage values.

Costs of retired, sold or abandoned properties that constitute a part of an amortization base (partial field) are charged or credited, net of proceeds, to accumulated DD&A unless doing so significantly affects the unit-of-production amortization rate for an entire field, in which case a gain or loss is recognized currently. No gain or loss for the sale of oil and natural gas producing properties was recorded for the years ended December 31, 2013, 2012 or 2011.

Expenditures for maintenance, repairs and minor renewals necessary to maintain properties in operating condition are expensed as incurred. Major betterments, replacements and renewals are capitalized to the appropriate property and equipment accounts. Estimated dismantlement and abandonment costs for oil and natural gas properties are capitalized, net of salvage, at their estimated net present value and amortized on a unit-of-production basis over the remaining life of the related proved developed reserves.

The factors used to determine fair value are subject to management’s judgment and expertise and include, but are not limited to, recent sales prices of comparable properties, the present value of future cash flows, net of estimated operating and development costs using estimates of proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures and various discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flows projected. These assumptions represent Level 3 inputs, as further discussed in Note 6 — Fair Value Measurements. No impairment of proved oil and natural gas properties was recorded for the years ended December 31, 2013, 2012 and 2011.

Unproved Oil and Gas Properties

Unproved properties consist of costs incurred to acquire unproved leases, or lease acquisition costs. Lease acquisition costs are capitalized until the leases expire or when the Company specifically identifies leases that will revert to the lessor, at which time the Company expenses the associated lease acquisition costs. The expensing of the lease acquisition costs is recorded as impairment of oil and gas properties in the Consolidated Statement of Operations. Lease acquisition costs related to successful exploratory drilling are reclassified to proved properties and depleted on a unit-of-production basis.

F-12

The Company assesses its unproved properties periodically for impairment on a property-by-property basis based on remaining lease terms, drilling results or future plans to develop acreage. The Company considers the following factors in its assessment of the impairment of unproved properties:

● the remaining amount of unexpired term under its leases;

● its ability to actively manage and prioritize its capital expenditures to drill leases and to make payments to extend leases that may be close to expiration;

● its ability to exchange lease positions with other companies that allow for higher concentrations of ownership and development;

● its ability to convey partial mineral ownership to other companies in exchange for their drilling of leases; and

● its evaluation of the continuing successful results from the application of completion technology in the Bone Spring and Wolfcamp  formations by the Company or by other operators in areas adjacent to or near the Company’s unproved properties.

For sales of entire working interests in unproved properties, gain or loss is recognized to the extent of the difference between the proceeds received and the net carrying value of the property. Proceeds from sales of partial interests in unproved properties are accounted for as a recovery of costs unless the proceeds exceed the entire cost of the property. In 2012 and 2011, the Company sold unproved lease acreage located in the Permian Basin in Texas for an aggregate of $ 592,702 and $ 34,667 in cash. The Company recognized a gain of $ 402,901 and $ 34,467 from these divestures, respectively.

Exploration Expenses

Exploration costs, including certain geological and geophysical expenses and the costs of carrying and retaining undeveloped acreage, are charged to expense as incurred.

Costs from drilling exploratory wells are initially capitalized, but charged to expense if and when a well is determined to be unsuccessful. Determination is usually made on or shortly after drilling or completing the well, however, in certain situations a determination cannot be made when drilling is completed. As of December 31, 2013, the Company had no exploratory well costs.

Asset Retirement Obligations

In accordance with the Financial Accounting Standard Board’s (“FASB”) authoritative guidance on asset retirement obligations (“ARO”), the Company records the fair value of a liability for a legal obligation to retire an asset in the period in which the liability is incurred with the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. For oil and gas properties, this is the period in which the well is drilled or acquired. The ARO represents the estimated amount the Company will incur to plug, abandon and remediate the properties at the end of their productive lives, in accordance with applicable state laws. The liability is accreted to its present value each period and the capitalized costs are amortized using the unit-of-production method. The accretion expense is recorded as a component of depreciation, depletion and amortization in the Company’s Consolidated Statement of Operations.

The Company determines the ARO by calculating the present value of estimated cash flows related to the liability. Estimating the future ARO requires management to make estimates and judgments regarding timing and existence of a liability, as well as what constitutes adequate restoration. Inherent in the fair value calculation are numerous assumptions and judgments including the ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments.  These assumptions represent Level 3 inputs, as further discussed in Note 4 — Fair Value Measurements. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the related asset.

F-13

Revenue Recognition

Oil and gas revenue from the Company’s interests in producing wells is recognized when the product is delivered, at which time the customer has taken title and assumed the risks and rewards of ownership, and collectability is reasonably assured. Substantially all of the Company’s production is sold to purchasers under short-term (less than twelve months) contracts at market-based prices. The sales prices for oil and natural gas are adjusted for transportation and other related deductions. These deductions are based on contractual or historical data and do not require significant judgment. Subsequently, these revenue deductions are adjusted to reflect actual charges based on third-party documents. Since there is a ready market for oil and natural gas, the Company sells the majority of its production soon after it is produced. As a result, the Company maintains a minimum amount of product inventory in storage.

Production Taxes

The Company pays taxes and royalties on oil and natural gas in accordance with the laws and regulations applicable to those agreements.

Concentrations of Market and Credit Risk

The future results of the Company’s oil and natural gas operations will be affected by the market prices of oil and natural gas. The availability of a ready market for oil and natural gas products in the future will depend on numerous factors beyond the control of the Company, including weather, imports, marketing of competitive fuels, proximity and capacity of oil and natural gas pipelines and other transportation facilities, any oversupply or undersupply of oil, natural gas and liquid products, the regulatory environment, the economic environment, and other regional and political events, none of which can be predicted with certainty.

The Company operates in the exploration, development and production sector of the oil and gas industry. The Company’s receivables include amounts due from purchasers of its oil and natural gas production. While certain of these customers are affected by periodic downturns in the economy in general or in their specific segment of the oil or natural gas industry, the Company believes that its level of credit-related losses due to such economic fluctuations has been and will continue to be immaterial to the Company’s results of operations over the long-term. 

Environmental Costs

Environmental expenditures are expensed or capitalized, as appropriate, depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations, and which do not have future economic benefit, are expensed. Liabilities related to future costs are recorded on an undiscounted basis when environmental assessments and/or remediation activities are probable and the costs can be reasonably estimated.

Income Taxes

Arabella Exploration, Inc. has identified the Cayman Islands as its only “major” tax jurisdiction, as defined.  Arabella Exploration, Inc. has received an undertaking from the Governor-in-Cabinet of the Cayman Islands that, in accordance with section 6 of the Tax Concessions Law (Revised) of the Cayman Islands, for a period of 20 years from the date of the undertaking, no law which is enacted in the Cayman Islands imposing any tax to be levied on profits, income, gains or appreciations shall apply to Arabella Exploration, Inc. or its operations and, in addition, that no tax to be levied on profits, income, gains or appreciations or which is in the nature of estate duty or inheritance tax shall be payable (i) on the Company’s securities or our debentures or other obligations or (ii) by way of the withholding in whole or in part of a payment of dividend or other distribution of income or capital by Arabella Exploration, Inc. to its security holders or a payment of principal or interest or other sums due under a debenture or other obligation.

Based on the Company’s evaluation, it has been concluded that there are not significant uncertain tax positions requiring recognition in the Company’s financial statements.  Since Arabella Exploration, Inc. was incorporated on June 17, 2010, the evaluation was performed for the 2010, 2011 and 2012 tax years which will be the only periods subject to examination.  The Company believes that its income tax positions and deductions would be sustained on audit and does not anticipate any adjustments that would result in material changes to its financial position.

F-14

During 2013, 2012 and 2011, Arabella Exploration LLC was not a taxable entity for federal income tax purposes. Accordingly, Arabella did not directly pay federal income tax. Arabella Exploration LLC’s taxable income or loss, which may vary substantially from the net income or net loss Arabella Exploration LLC’s reports in Arabella Exploration, Inc.’s consolidated statement of income, is includable in the federal income tax returns of the member.

Going forward in 2014, the Company expects to be a taxable corporate entity.

Fair Value of Financial and Non-Financial Instruments

The carrying value of cash and cash equivalents, accounts receivable, accounts payable and other payables approximate their respective fair market values due to their short-term maturities. At December 31, 2013 the Company’s cash equivalents are Level 1 assets. The Company’s asset retirement obligations are also recorded on the Consolidated Balance Sheet at amounts which approximate fair market value. See Note 6 — Fair Value Measurements.

Earnings per Share

Basic earnings per share is computed by dividing income available to common shareholders by the weighted average number of shares outstanding for the periods presented. The calculation of diluted earnings per share does not include the potential dilutive impact of the 4,106,500 offering warrants outstanding during the periods presented since the exercise of the offering warrants is contingent upon the effectiveness of a registration statement to be filed with the SEC.  The calculation of diluted earnings per share does not include the potential dilutive impact of the Unit Purchase Option as it was not exercisable based on the Company’s share price.

The calculation of diluted earnings per share does include the dilutive impact of the 6,600,000 Insider Warrants as they were sold pursuant to an exemption from the registration requirements of the Securities Act. For the period between the Acquisition and the end of the year the weighted average share price of the company was approximately $7.63 resulting in a potential dilutive effect of 43,610 shares based on the treasury method. With the impact of the foregoing, weight average shares outstanding was 3,201,305 on a diluted basis.

6. Fair Value Measurements

In accordance with the FASB’s authoritative guidance on fair value measurements, the Company’s financial assets and liabilities are measured at fair value on a recurring basis. The Company recognizes its non-financial assets and liabilities, such as asset retirement obligations and proved oil and natural gas properties upon impairment, at fair value on a non-recurring basis.

As defined in the authoritative guidance, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). To estimate fair value, the Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable.

The authoritative guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (“Level 1” measurements) and the lowest priority to unobservable inputs (“Level 3” measurements). The three levels of the fair value hierarchy are as follows:

Level 1  — Unadjusted quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2  — Pricing inputs, other than unadjusted quoted prices in active markets included in Level 1, are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument and can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.

Level 3  — Pricing inputs are generally less observable from objective sources, requiring internally developed valuation methodologies that result in management’s best estimate of fair value.

F-15

    Nonfinancial Assets and Liabilities

Asset retirement obligations. The carrying amount of the Company’s Asset Retirement Obligations, or ARO, in the Consolidated Balance Sheet at December 31, 2013 is $ 21,171 (see Note 6 — Asset Retirement Obligations). The Company determines the ARO by calculating the present value of estimated future cash flows related to the liability. Estimating the future ARO requires management to make estimates and judgments regarding timing and existence of a liability, as well as what constitutes adequate restoration. Inherent in the fair value calculation are numerous assumptions and judgments, including the ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. These assumptions represent Level 3 inputs. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the related asset.

Impairment. The Company reviews its proved oil and natural gas properties on a field by field basis for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. The Company estimates the expected undiscounted future cash flows of its oil and natural gas properties and compares such amounts to the carrying amount of the oil and natural gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will adjust the carrying amount of the oil and natural gas properties to fair value. The factors used to determine fair value are subject to management’s judgment and expertise and include, but are not limited to, recent sales prices of comparable properties, the present value of future cash flows, net of estimated operating and development costs using estimates of proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures and various discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flows projected. These assumptions represent Level 3 inputs. No impairment charges on proved oil and natural gas properties were recorded for the years ended December 31, 2013, 2012 or 2011.

7. Oil and Gas Properties

The following table sets forth the Company’s oil and gas properties:

	December 31,
	2013			2012
	(In thousands)
Proved oil and gas properties (1)	$	7,491,321		$	500,883
Less: Accumulated depreciation, depletion, amortization and impairment		(484,968	)		(15,858	)
Proved oil and gas properties, net		7,006,353			485,025
Unproved oil and gas properties		6,243,014			1,031,211
Total oil and gas properties, net	$	13,249,367		$	1,516,236

(1) Included in the Company’s proved oil and gas properties are estimates of future asset retirement costs of $20,267 and $2,722 at December 31, 2013 and 2012, respectively.

8. Asset Retirement Obligations

The following table reflects the changes in the Company’s ARO during the years ended December 31, 2013 and 2012:

	Year Ended December 31,
	2013		2012
	(In thousands)
Asset retirement obligation — beginning of period	$	2,963	$	2,796
Additions to ARO from new properties		17,545		2,638
Sales or abandonments of properties		—		(2,686	)
Accretion expense during period		663		215
Asset retirement obligation — end of period	$	21,171	$	2,963

F-16

9. Note Payable to Officer

As of December 31, 2013, the Company’s note payable is payable to Jason Hoisager, the founder of Arabella Exploration LLC, with an outstanding balance of $ 3,007,170. The founder is currently the President of the Company and is a director and majority shareholder of the Company. The note payable is non-interest bearing and matures in December of 2023.

10. Shareholders’ Equity

The Company is authorized to issue 50,000,000 ordinary shares and 5,000,000 preferred shares with a par value of $0.001 per share.

     Preferred Shares

The Company is authorized to issue up to 5,000,000 preferred shares with a par value of $0.001 and such designation as may be determined by the Board of Directors of the Company from time to time.

     Warrants

  In connection with the Offering for the Parent in March 2011, the Company issued 4,106,500 warrants, which entitles the holders to purchase ordinary shares at the price of $5.00 per share, commencing on the date of the merger, if the Company has an effective and current registration statement covering the ordinary shares issuable upon exercise of the warrants and a current prospectus relating to such ordinary shares, and expiring three years from that date.  The Company may redeem the Warrants at a price of $0.01 per Warrant upon 30 days’ notice while the Warrants are exercisable, only when the last sale price of the ordinary shares is at least $10.50 per share for any 20 trading days within a 30 trading day period, provided that a current registration statement is in effect for the ordinary shares underlying the warrants.  If not exercised, the warrants expire on December 24, 2016.  If the Company redeems the warrants, management of the Company will have the option to require any holder that wishes to exercise his warrants to do so on a cashless basis.

Simultaneously to the Offering, certain of the shareholders purchased 6,600,000 warrants at the price of $0.35 per warrant (for an aggregate purchase price of $ 2,310,000) from the Company.  These warrants have the same terms as the 4,106,500 public warrants referred to in the preceding paragraph, except these warrants are not redeemable and these warrants are exercisable for cash or on a cashless basis.

F-17

      Unit Purchase Option

In connection with the Offering, the Company issued a unit purchase option to purchase 400,000 units at an exercise price of $ 8.80 per unit to its underwriters.  Each unit consists of one ordinary share and one redeemable ordinary share purchase warrant, which contains a provision for cashless exercise and has the same terms as the 4,106,500 public warrants.  The fair value of the option at the date of grant was $1,486,000 ($ 3.72 per unit) using a Black-Scholes option-pricing model. The fair value of the unit purchase option granted to the underwriter was estimated as of the date of grant using the following assumptions:  (1) expected volatility of 54.1%, (2) risk-free interest rate of 2.625%, and (3) expected life of 5 years.  The unit purchase option may be exercised for cash or on a cashless basis at the holder’s option.

11. Related Party Transactions

Mr. Jason Hoisager, the Company’s Chief Executive Officer, owns 100% of Arabella Petroleum Company LLC (“Petroleum”), which is the operating company for substantially all the wells that the Company has its working interest in.   As Petroleum drills and completes the wells, Petroleum bills the Company for its working ownership percentage of the capital costs.  After the completion of each well, Petroleum sells the oil and gas and provides the Company its working interest revenue, net of production taxes and charges for the lease operating expenses.

As of December 31, 2013 and 2012, The Company owed Petroleum $3,695,119 and $42,238, respectively in joint interest billings to vendors for the well costs.  During 2013, The Company paid Petroleum $3,589,903 in capital costs for the wells.  Petroleum is responsible for collecting the revenue from the purchasers and providing the Company its accounts receivable, which totaled $425,372 and $702 at December 31, 2013 and 2012, respectively.

Petroleum also paid part of the general and administrative expenses for the companies and allocated to Exploration $131,950, $93,845 and $30,071 for the years 2013, 2012 and 2011, respectively.

12. Significant Concentrations

Major customers. For the year ended December 31, 2013, sales, through Petroleum, to Sunoco Partners, and Enterprise Crude Oil accounted for approximately 78% and 10% of our total sales, respectively. For the year ended December 31, 2012, sales to Elephant Oil & Gas and LPC Crude Oil, Inc. accounted for approximately 60%, and 25%, respectively, of our total oil and gas sales. For the year ended December 31, 2011, sales to Elephant Oil & Gas accounted for approximately 65% of our oil and gas sales.   No other purchasers accounted for more than 10% of the Company’s total sales for the years ended December 31, 2013, 2012 and 2011. Substantially all of the Company’s accounts receivable result from sales of oil and natural gas.

This concentration of customers may impact the Company’s overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions. Management believes that the loss of any of these purchasers would not have a material adverse effect on the Company’s operations, as there are a number of alternative oil and natural gas purchasers in the Company’s producing region.

13. Commitments and Contingencies

Employment agreement.  On December 24, 2013, Arabella entered into an employment agreement with Jason Hoisager pursuant to which Mr. Hoisager agreed to act as the Chief Executive Officer and President.  The employment agreement has a term of one year and will automatically renew for additional one year terms after the end of the initial term if the agreement is not terminated at least 90 days prior to the end of the applicable term.  The employment agreement provides for a base salary of $300,000 a year, with a bonus determined by the board of directors.  If the board of directors terminates the agreement without cause, Mr. Hoisager terminates the employment agreement for good reason, or Mr. Hoisager’s employment is terminated within six months after a change of control, Mr. Hoisager will be entitled to severance equal to 24 months of his base salary and an amount equal to his bonus for the prior year.

Lease obligations. Petroleum has the operating lease for the Company’s office space, and beginning in January 2014, the Company is paying the rent for the office lease.

F-18

Future minimum annual rental commitments under the non-cancelable office lease at December 31, 2013 are as follows:

	(In thousands)
2014	$	217,281
2015		230,510
2016		236,875
2017		59,872
Thereafter		—
	$	744,538

Drilling contracts. As of December 31, 2013, Petroleum had a drilling rig contract at a cost of $21,500 per day with initial terms of six months that ended on March 31, 2014, and Petroleum extended the contract for an additional six month period. In the event of early contract termination under this contract, the Company would not be obligated to pay its working interest portion through the end of the primary term of the contract.

Litigation. The Company is party to various legal proceedings from time to time arising in the ordinary course of business. The Company believes all such matters are without merit or involve amounts which, if resolved unfavorably, either individually or in the aggregate, will not have a material adverse effect on its financial condition, results of operations or cash flows.

Arbitration. Baker Hughes Oilfield Operations, Inc. (“BH”) and Arabella Petroleum Company (“Petroleum”), the operating company for and an affiliate of Arabella Exploration, LLC, are currently in arbitration concerning work BH claims it performed, and on which it claims is owed $3,191,181, plus interest, on the Company’s SM Prewitt #1H well.  In conjunction with such claim, BH has filed a lien on the SM Prewitt #1H.  Petroleum does not believe such amounts are owed to BH due to the failure of BH to satisfactorily perform the services it was contracted to perform.  The Company has a 14.55% working interest in this well and, were BH to prevail, could be responsible for 14.55% of any awards granted BH in arbitration.

14. Subsequent Event

In March 2014, Arabella sold a leased undeveloped acreage for approximately $2.1 million in cash and recognized a gain on the sale of the property of approximately $1.2 million.

On May 1, 2014 the Company received a loan from Hauser Holdings, LLC an affiliate of Richard Hauser, one of our directors.  The $800,000 loan is due August 31, 2014 and bears an interest rate of 10% per annum.

Management evaluates events that have occurred after the balance sheet date but before the financial statements are issued. Based upon the review, Management did not identify any recognized or non-recognized subsequent events, other than those discussed above, which would have required an adjustment or disclosure in the financial statements.

15. Supplemental Oil and Gas Reserve Information (Unaudited)

The estimates of proved oil and gas reserves utilized in the preparation of the consolidated financial statements were prepared by independent petroleum engineers.  Such estimates are in accordance with guidelines established by the SEC and the FASB.  All of our reserves are located in the United States.  For information about our results of operations from oil and gas activities, see the accompanying consolidated statements of operations.

We emphasize that reserve estimates are inherently imprecise.  Accordingly, the estimates are expected to change as more current information becomes available.  In addition, a portion of our proved reserves are classified as proved developed nonproducing and proved undeveloped, which increases the imprecision inherent in estimating reserves which may ultimately be produced.

During the year ended December 31, 2013, properties totaling $4,774,306 were transferred to us from Petroleum, a company under common control and that transfer had a significant impact on our proved reserves. Accordingly, we have included supplemental oil and gas reserve information to give effect to the additional proved reserves on properties owned by Petroleum in prior periods and transferred to the Company.

At December 31, 2011, we had no significant proved reserves and accordingly, our reserve information is as of December 31, 2012 and for the year then ended. Properties assigned to us and subsequently sold were treated as unproved properties. We had capital costs of $63,398 relating to exploratory wells pending the determination of proved reserves as of December 31, 2011, respectively. All capital costs related to exploratory wells at December 31, 2011 were transferred to proved properties in 2012.  There were no exploratory wells after 2011.

F-19

The following table sets forth estimated proved reserves together with the changes therein (Oil and NGL in Bbls, gas in Mcf, gas converted to BOE by dividing Mcf by six) for the years ended December 31, 2012 and 2013, giving effect to reserves associated with properties owned by Petroleum during the period and transferred to us in 2013:

	Oil		Gas		BOE
Balance at December 31, 2010	-		-			-
Purchase and assignment of minerals in place	13,720		-			13,720
Balance at December 31, 2011	13,720		-			13,720
Purchase and discoveries of minerals in place	153,280		378,511			216,365
Production	(679	)	(1,338	)		(902	)
Balance at December 31, 2012	166,321		377,173			229,183
Revisions	171,385		310,181			223,082
Purchase and discoveries of minerals in place	1,216,611		2,521,015			1,636,780
Production	(13,915	)	(11,048	)		(15,756	)
Balance at December 31, 2013	1,540,402		3,197,321			2,073,289

The standardized measure of discounted future net cash flows relating to estimated proved reserves as of December 31, 2013, 2012 and 2011, as recast, giving effect to reserves associated with properties owned by Petroleum during the period and transferred to us in 2013, was as follows (In thousands):

	2013			2012			2011
Future cash inflows	$	152,038		$	17,034		$	1,146
Future costs:
Production		(31,849	)		(4,326	)		(466	)
Development		(31,885	)		(5,761	)		(225	)
Future net cash inflows		88,304			6,947			455
10% discount factor		(55,512	)		(4,239	)		(361	)
Standardized measure of discounted net cash flows	$	32,792		$	2,708		$	94

Changes in the standardized measure of discounted future net cash flows relating to estimated proved reserves for the year ended December 31, 2013, giving effect to reserves associated with properties owned by Petroleum during the period and transferred to us in 2013, was as follows (In thousands):

F-20

	2013			2012			2011
Standardized measure at beginning of period	$	2,708		$	94		$	-
Sales, net of production costs		(1,206	)		(50	)		-
Revisions		7,372			-			-
Purchases and discoveries of minerals in place		23,918			2,664			94
Standardized measure at end of period	$	32,792		$	2,708		$	94

The estimated present value of future cash flows relating to estimated proved reserves is extremely sensitive to prices used at any measurement period.  The average prices used for each commodity for the year ended December 31, 2013 and 2012 was as follows:

	Average Price
	Oil		Gas
December 31, 2012	$	89.14	$	7.23
December 31, 2013	$	91.24		6.06

Average prices for December 31, 2013 and 2012 were based on the 12-month un-weighted arithmetic average of the first-day-of-the-month price for the period from January through December during each respective calendar year.

Analysis of Reserves

The following table presents Arabella’s estimated net proved oil and natural gas reserves and the present value of Arabella’s reserves as of December 31, 2013 and December 31, 2012, based on the reserve report prepared by WPC, and such reserve reports have been prepared in accordance with the rules and regulations of the SEC. All Arabella’s proved reserves included in the reserve reports are located in North America.

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	December 31, 2013 (1) (2)		December 31, 2012 (1) (2)		December 31, 2011 (1) (2)
Estimated proved developed reserves:
Oil (MBbls)		118.5		7.7		-
Natural gas (MMcf)		211.4		6.4		-
Natural gas liquids (MBbls)		-		-		-
Total (MBOE)		153.7		8.8		-
Estimated proved undeveloped reserves:
Oil (MBbls)		1,421.9		158.6		13.7
Natural gas (MMcf)		2,985.9		370.8		-
Natural gas liquids (MBbls)		-		-		-
Total (MBOE)		1,919.6		222.1		13.7

Estimated Net Proved Reserves:
Oil (MBbls)	1,540.4		166.3		13.7
Natural gas (MMcf)	3,197.3		377.2		-
Natural gas liquids (MBbls)	-		-		-
Total (MBOE)	2,073.3		229.2		13.7
Percent proved developed	7.4	%	3.8	%	-	%
Probable reserves
Oil (MBbls)	2,961.5		1,414.8		-
Natural gas (MMCF)	6,219.1		1980.7		-
Natural gas liquids (MBbls)	-		-		-
Total (MBOE)	3,998.0		1744.9		-
Possible reserves
Oil (MBls)	4,092.8		297.9		149.8
Natural gas (MMCF)	8,594.9		417.1		208.5
Natural gas liquids (MBbls)	-		-		-
Total (MBOE)	5,525.3		367.4		183.6

(1) Estimates of reserves as of December 31, 2013, 2012 and 2011, were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month within the 12-month periods ended December 31, 2013, 2012 and 2011, respectively, in accordance with revised SEC guidelines applicable to reserves estimates as of the end of such periods. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for undeveloped acreage. The reserve estimates represent Arabella’s net revenue interest in Arabella’s properties. Although Arabella believes these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates.

(2) The reserves at December 31, 2012 and 2011 include reserves associated with properties owned by Petroleum during the period and transferred to us in 2012 and 2013.

The foregoing reserves are all located within the continental United States. Reserve engineering is a subjective process of estimating volumes of economically recoverable oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. As a result, the estimates of different engineers often vary. In addition, the results of drilling, testing and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered. Estimates of economically recoverable oil and natural gas and of future net revenues are based on a number of variables and assumptions, all of which may vary from actual results, including geologic interpretation, prices and future production rates and costs. Arabella has not filed any estimates of total, proved net oil or natural gas reserves with any federal authority or agency other than the SEC.

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