Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

ANNUAL REPORT

PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

FOR THE FISCAL YEAR ENDED JUNE 30, 2014

COMMISSION FILE NUMBER 001-34144

CUBIC ENERGY, INC.

(Exact Name of Registrant as Specified in its Charter)

9870 PLANO ROAD, DALLAS, TEXAS 75238

(Address of Principal Executive Offices)

972-686-0369

(Registrant’s Telephone Number)

Securities registered pursuant to Section 12(b) of the Act:

Securities registered under Section 12(g) of the Act: Common Stock, $0.05 par value

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

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

Indicate by check mark whether the registrant (1) 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 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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o

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

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

State the aggregate market value of the common stock, par value $0.05 per share, held by non-affiliates computed by reference to the price at which the common stock was last sold, as of the last business day of the registrant’s most recently completed second fiscal quarter: As of December 31, 2013 the aggregate market value held by non-affiliates was $10,638,367.

Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date: As of November 4, 2014, there were 77,505,908 shares of common stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE: None.

Table of Contents

Special note regarding forward-looking statements

This annual report on Form 10-K contains forward-looking statements. All statements, other than statements of historical facts, are forward-looking statements. These forward-looking statements relate to, among other things, the following: our future financial and operating performance and results; our business strategy; market prices; and our plans and forecasts.

Forward-looking statements are identified by use of terms and phrases such as “may,” “expect,” “estimate,” “project,” “plan,” “believe,” “intend,” “achievable,” “anticipate,” “will,” “continue,” “potential,” “should,” “could” and similar words and phrases. Although we believe that the expectations reflected in these forward-looking statements are reasonable, they do involve certain assumptions, risks and uncertainties. Our actual results could differ materially from those anticipated in these forward-looking statements. You should consider carefully the statements in the “Risk Factors” section of this report and other sections of this report, which describe factors that could cause our actual results to differ from those set forth in the forward-looking statements, including, but not limited to, the following factors:

·                  our ability to generate sufficient cash flow from operations, borrowings or other sources to enable us to continue operations, service our debt and fully develop our undeveloped acreage positions;

·                  our ability to integrate our recently consummated acquisitions;

·                  the volatility in commodity prices for oil and natural gas;

·                  the possibility that the industry may be subject to future regulatory or legislative actions (including additional taxes);

·                  the presence or recoverability of estimated oil and natural gas reserves and the actual future production rates and associated costs;

·                  the ability to replace oil and natural gas reserves;

·                  lease or title issues or defects to our oil and gas properties;

·                  environmental risks;

·                  drilling and operating risks;

·                  exploration and development risks;

·                  competition, including competition for acreage in oil and natural gas producing areas;

·                  management’s ability to execute our plans to meet our goals;

·                  our ability to retain key members of senior management;

·                  our ability to obtain goods and services, such as drilling rigs and other oilfield equipment, and access to adequate gathering systems and pipeline take-away capacity, to execute our drilling program;

·                  general economic conditions, whether internationally, nationally or in the regional and local market areas in which we do business, may be less favorable than expected, including that the United States economic slow-down might continue to negatively affect the demand for natural gas, oil and natural gas liquids;

·                  continued hostilities in the Middle East and other sustained military campaigns or acts of terrorism or sabotage; and

·                  other economic, competitive, governmental, legislative, regulatory, geopolitical and technological factors that may negatively impact our business, operations or pricing.

All forward-looking statements are expressly qualified in their entirety by the cautionary statements in this paragraph and elsewhere in this document. Other than as required under the securities laws, we do not assume a duty to update these forward-looking statements, whether as a result of new information, subsequent events or circumstances, changes in expectations or otherwise.

ii

Table of Contents

CUBIC ENERGY, INC.

TABLE OF CONTENTS

iii

Table of Contents

PART I

Item 1.         Business.

GENERAL

Cubic Energy, Inc. (referred to as “Cubic”, “we”, “our”, “us” or the “Company”) is the parent company of two wholly owned direct subsidiaries (Cubic Asset Holding, LLC, a Delaware limited liability company (“Cubic Asset Holding”), and Cubic Louisiana Holding, LLC, a Delaware limited liability company (“Cubic Louisiana Holding”)), and two wholly owned indirect subsidiaries (Cubic Asset LLC, a Delaware limited liability company and a direct subsidiary of Cubic Asset Holding (“Cubic Asset”), and Cubic Louisiana, LLC, a Delaware limited liability company and a direct subsidiary of Cubic Louisiana Holding (“Cubic Louisiana”)). Unless the context otherwise requires, references to the Company herein refer to the Company and its subsidiaries, on a consolidated basis.

The Company is an independent energy company engaged in the development and production of, and exploration for, crude oil, natural gas and natural gas liquids. Our oil and gas assets are concentrated in Texas and Louisiana. At June 30, 2014, our total proved reserves were 135,071,173 Mcfe.

RECENT DEVELOPMENTS

On July 14, 2014, we entered into an Amendment, Forbearance and Waiver Agreement (the “Amendment”) with the holders of the Notes due October 2016 (the “Notes”), which were issued pursuant to a Note Purchase Agreement dated October 2, 2013, (the “Note Purchase Agreement”), and certain other parties thereto. The Company initially issued as aggregate of $66,000,000 of the Notes. The Notes originally bore interest at the rate of 15.5% per annum, in cash, payable quarterly; provided, however, that interest for the first six months following the closing was paid 7.0% per annum in cash and 8.5% per annum in additional Notes.

Pursuant to the Amendment, the holders of the Notes waived various defaults specified in the Amendment, and the parties agreed to modify certain covenants in the Note Purchase Agreement.  The holders of the Notes also waived their right to receive Default Interest and Registration Default Interest (as such terms are defined in the Note Purchase Agreement).  In addition, the Amendment provides that after March 31, 2014, the interest rate applicable to the Notes is increased from 15.5% per annum to 20.5% per annum; provided that after such date interest shall not be payable in cash but shall accrue and compound on a quarterly basis.

The Amendment includes an additional covenant requiring the Company, among other things, by no later than October 17, 2014, to enter into a definitive agreement with respect to a Strategic Transaction (as defined below) that is reasonably expected to be consummated no later than December 31, 2014.  A Strategic Transaction includes a transaction resulting in the complete repayment of the Notes, or another transaction acceptable to the holders of the Notes.  We continue to explore alternatives with respect to a Strategic Transaction, although we did not enter into a definitive agreement by October 17, 2014.  We are in discussions with the holders of the Notes with respect to available alternatives.  Unless the requirement regarding a Strategic Transaction is waived, or we obtain an extension of time, the holders of the Notes could declare a default under the Note Purchase Agreement, accelerate the indebtedness represented by the Notes and exercise all other remedies available to them, including foreclosing on our assets.

The accompanying financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note A to the financial statements, the Company has suffered recurring losses from operations and has a net working capital deficiency that raise substantial doubt about its ability to continue as a going concern. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

1

Table of Contents

ASSETS

Legacy Louisiana Acreage

Our corporate strategy with respect to our asset acquisition and development efforts was to position the Company in low risk opportunities while building mainstream high yield reserves.  The acquisition of our acreage in DeSoto and Caddo Parishes, Louisiana, puts us in reservoir rich environments in the Hosston, Cotton Valley and Bossier/Haynesville Shale formations, with additional shallow formations to exploit as well. We have had success on our acreage with wells completed in the Hosston, Cotton Valley and Bossier/Haynesville Shale formations.  We also own interests in the rights-of-way, infrastructure and pipelines for our Caddo and DeSoto Parish, Louisiana acreage.

We share our Cotton Valley and Bossier/Haynesville formation acreage with Goodrich Petroleum Corporation (“Goodrich”), Chesapeake Energy Corporation (“Chesapeake”), BHP Billiton Limited (“BHP Billiton”), EP Energy E&P Company, L.L.P. (“EP Energy”), BG US Production Company, LLC (“BG”), EXCO Operating Company, LP (“EXCO”) and Indigo Minerals, LLC (“Indigo Minerals”), and all of these companies are third-party operators actively working on some of our shared acreage.   Two new wells that came on line in the second half of fiscal 2014 helped boost production from our legacy Louisiana properties.

Legacy Texas Acreage

Prior to our acquisition of properties in Leon and Robertson Counties, Texas, described below, our Texas properties were situated in Eastland and Callahan Counties. These Texas properties consist primarily of wells acquired in several transactions between 1991 and 2002 and through overriding royalty interests reserved in farm-out agreements in 1998 and 1999. These wells produce limited amounts of natural gas and oil condensate.

Other Texas Acreage and Louisiana Working Interests

In October 2013, we acquired proven reserves, oil & natural gas production and undeveloped leasehold interests in Leon and Robertson Counties, Texas, that puts us in the additional reservoir rich environments in the Eagle Ford, Woodbine, Austin Chalk, Buda, Glen Rose and Georgetown formations, with additional shallow formations to exploit as well. We also acquired additional rights in our leasehold interests in DeSoto and Caddo Parishes, Louisiana. The acquisitions are summarized as follows:

·                  The Company consummated the transactions contemplated by the Purchase and Sale Agreement dated as of April 19, 2013 (the “Gastar Agreement”) with Gastar Exploration Texas, LP (“Gastar”) and Gastar Exploration USA, Inc.  Pursuant to the Gastar Agreement, the Company acquired proven reserves, oil & natural gas production and undeveloped leasehold interests in Leon and Robertson Counties, Texas.  The acquired properties include approximately 17,400 net acres of leasehold interests.  The acquisition price paid by the Company at closing was $39,188,300, following various adjustments set forth in the Gastar Agreement, and net of the various deposits paid prior to the closing date.  For purposes of allocating revenues and expenses and capital costs between Gastar and us, such amounts were netted effective January 1, 2013 and have been recorded as an adjustment to the purchase price.

·                  The Company also consummated the transactions contemplated by the Purchase and Sale Agreement dated as of September 27, 2013 (the “Navasota Agreement”) with Navasota Resources Ltd., LLP (“Navasota”). Pursuant to the Navasota Agreement, the Company acquired proven reserves, oil & natural gas production and undeveloped leasehold interests in Leon and Robertson Counties, Texas.  The leasehold interests acquired consists of additional fractional interests in the properties acquired pursuant to the Gastar Agreement, comprising approximately 6,400 net acres.  The acquisition price paid by the Company was $19,400,000, prior to certain post-closing adjustments.

2

Table of Contents

·                  In addition, the Company entered into and consummated the transactions contemplated by a Purchase and Sale Agreement dated as of October 2, 2013 (the “Tauren Agreement”) with Tauren Exploration, Inc. (“Tauren”), an entity controlled by Calvin A. Wallen, III, our Chairman of the Board, President and Chief Executive Officer (“Mr. Wallen”).  Pursuant to the Tauren Agreement, the Company acquired well bores, proven reserves, oil & natural gas production and undeveloped leasehold interests in the Cotton Valley formation in DeSoto and Caddo Parishes, Louisiana.  The acquired leasehold interests consist of additional percentage interests in the same leaseholds as our legacy Louisiana properties. The acquisition price paid by the Company was $4,000,000 in cash and 2,000 shares of the Company’s Series B Convertible Preferred Stock with an aggregate stated value of $2,000,000 and a fair value of $368,000.  The Tauren Agreement was unanimously approved by the Company’s board of directors, excluding Mr. Wallen.

We have seen success on our acquired Texas acreage and Louisiana acreage with two wells drilled by EXCO achieving production from the Haynesville shale formation in Louisiana during fiscal 2014.

The Texas legacy acreage, some of the Cotton Valley and Hosston formations in our legacy Louisiana acreage, and the Leon and Robertson Counties, Texas, acreage are operated by Fossil Operating, Inc. (“Fossil”), an entity controlled by Mr. Wallen.

HISTORY

Our predecessor was incorporated in October 1978. Cubic was incorporated in 1999 in the State of Texas. Our principal executive office is located at 9870 Plano Road, Dallas, Texas 75238, and our telephone number is (972) 686-0369.

On March 5, 2007, Cubic entered into a Credit Agreement with Wells Fargo Energy Capital, Inc. (“WFEC”) providing for a revolving credit facility of $20,000,000 and a convertible term loan of $5,000,000 (the “Credit Facility”). In connection with entering into the Credit Facility, the Company issued to WFEC warrants, with five-year expirations, for the purchase of up to 2,500,000 shares of Company Common Stock at an original exercise price of $1.00 per share. On December 18, 2009, the Company entered into a Second Amendment to Credit Agreement with WFEC, providing for a revolving credit facility of up to $40,000,000 subject to borrowing base limits and a convertible term loan of $5,000,000 (the “Amended Credit Agreement”). In connection with entering into the Amended Credit Agreement, the Company issued to WFEC additional warrants, expiring on December 1, 2014, for the purchase of up to 5,000,000 shares of Company Common Stock at an exercise price of $1.00 per share, and extended the expiration date of the warrants to purchase 2,500,000 shares of Company Common Stock that were previously issued to WFEC to December 1, 2017. In connection with the amendment, warrants held by WFEC, which are convertible into 8.5 million shares of the Company’s Common Stock, were modified to provide for an exercise price of $0.20 per share and a termination date of December 1, 2017.

On November 24, 2009, the Company entered into transactions with Tauren and Langtry Mineral & Development, LLC (“Langtry”), both of which are entities controlled by Mr. Wallen, under which the Company acquired $30,952,810 in pre-paid drilling credits (the “Drilling Credits”) applicable towards the development of its Haynesville Shale rights in Northwest Louisiana. As consideration for the Drilling Credits, the Company (a) conveyed to Tauren a net overriding royalty interest of approximately 2% in its leasehold rights below the Taylor Sand formation of the Cotton Valley and (b) issued to Langtry 10,350,000 Company common shares and Series A Convertible Preferred Stock in the amount of $10,350,000, which was convertible at any time prior to the fifth anniversary of issuance into Company common shares at $1.20 per common share. The preferred stock was entitled to cumulative dividends equal to 8% per annum, payable quarterly.

On December 18, 2009, the Company issued a subordinated promissory note payable to Mr. Wallen, in the principal amount of $2,000,000 (the “Wallen Note”). This note provided for interest at the prime rate plus one percent (1%). The proceeds of the Wallen Note were used to repay a previously outstanding promissory note.

3

Table of Contents

As of June 30, 2012, the Company used the Drilling Credits to fund $21,435,551 of its share of the drilling and completion costs for those horizontal Haynesville Shale wells drilled in sections previously operated by Fossil which are now operated by third parties. As of June 30, 2012 a total of $9,517,258 of the Drilling Credits remained. The counterparties (EXCO and BG) on the Drilling Credits asserted certain offsets against their obligations under the Drilling Credits. On September 12, 2012, we received a final judgment with respect to an arbitration award of approximately $12,800,000 from EXCO and BG.

On October 2, 2012, the Company entered into a Settlement Agreement and Mutual Release with Tauren, EXCO and BG. This agreement provides that EXCO and BG shall (a) apply the Drilling Credits as provided in the agreement and place the Company in consent status on specified wells in which the Company gets paid for production and (b) pay to the Company $12,179,853 in cash.  The agreement also provides for mutual releases among the parties.  Pursuant to the Fourth Amendment to Credit Agreement between the Company and WFEC, $9,134,890 of such amount was paid to WFEC when received from EXCO and BG in order to reduce the borrowings under the Company’s revolving credit facility with the balance of the cash received by the Company.

On October 2, 2013, the Company entered into the Note Purchase Agreement, pursuant to which the Company issued an aggregate of $66,000,000 of Notes to certain purchasers.  The Notes originally bore interest at the rate of 15.5% per annum, in cash, payable quarterly; provided, however, that interest for the first six months following the closing was paid 7.0% per annum in cash and 8.5% per annum in additional Notes. As described under “Recent Developments”, certain terms of the Note Purchase Agreement, including the interest rate, were modified as of March 31, 2014. The indebtedness under the Note Purchase Agreement is secured by substantially all of the assets of the Company, including a first priority lien over all of the assets of the Company, Cubic Asset and Cubic Asset Holding and a second priority lien over all of the assets of Cubic Louisiana and Cubic Louisiana Holding.

On October 2, 2013, the Company, through its subsidiary Cubic Asset, entered into a Call Option Structured Derivative arrangement with a third party that resulted in the receipt of an upfront payment at closing of approximately $35,000,000, through the sale of calls, which upfront payment approximated fair value of the calls sold at inception. As a result, the Call Option Structured Derivative arrangement was initially recognized and measured at the amount of its upfront payment.  Under the terms of the Call Option Structured Derivative arrangement, Cubic Asset sold calls to the third party covering (i) approximately 556,000 barrels of oil at a strike price set between $80 per barrel and $90 per barrel, and (ii) approximately 51.3 million MMBtu’s of gas at a strike price set between $3.45 per MMBtu and $3.90 per MMBtu. The scheduled volumes subject to the calls sold relate to production months from November 2013 through December 2018. The Company is subject to the price risks associated with product price changes that are in excess of the specified call prices.

On October 2, 2013, the Company, through its subsidiary Cubic Asset, entered into a Fixed Price Swap arrangement. Under the terms of the Fixed Price Swap arrangement, Cubic Asset will receive a fixed amount on approximately 18,000 barrels of oil at a price of $92 per barrel. The scheduled volumes subject to the swaps relate to production months from November 2013 through October 2016. Cubic Asset is subject to the price risks associated with product price increases above the specified fixed prices. The counterparties to this arrangement have a junior lien position on both of the assets of Cubic Asset and Cubic Louisiana.

In connection with the issuance and sale of the Notes under the Note Purchase Agreement, the Company issued certain warrants and shares of Series C Redeemable Voting Preferred Stock, par value $0.01 per share (the “Series C Redeemable Voting Preferred Stock”), to certain purchasers of the Notes and their affiliates (the “Investors”).  The Company issued warrants exercisable for (a) an aggregate of 65,834,549 shares of Common Stock, at an exercise price of $0.01 per share (the “Class A Warrants”), and (b) an aggregate of 32,917,275 shares of Common Stock, at an exercise price of $0.50 per share (the “Class B Warrants” and together with the Class A Warrants, the “Warrants”).

4

Table of Contents

The Company also issued an aggregate of 98,751.824 shares of Series C Redeemable Voting Preferred Stock to the Investors.  The holders of the Series C Redeemable Voting Preferred Stock are entitled to vote, together with holders of Common Stock, as a single class with respect to all matters presented to holders of Common Stock of the Company.  The holders of Series C Redeemable Voting Preferred Stock are entitled, in the aggregate, to a number of votes equal to the number of shares of Common Stock that would be issuable upon the exercise of all outstanding Warrants on a Full Physical Settlement basis (as defined in the Warrant and Preferred Stock Agreement).  The holders of Series C Redeemable Voting Preferred Stock are not entitled to receive any dividends from the Company.  Shares of the Series C Redeemable Voting Preferred Stock have a stated value of $0.01 per share and may be redeemed at the option of the holders thereof at any time.

In connection with entering into the Note Purchase Agreement and the Warrant and Preferred Stock Agreement, the Company entered into an Investment Agreement, dated as of October 2, 2013, with the Investors, pursuant to which the Investors have the right to designate three members (subject to adjustment for changes in board size) for election or appointment to the Company’s board of directors and certain information rights, veto rights, pre-emptive rights and sale rights, among others.

The Investors and Mr. Wallen also entered into a Voting Agreement, dated as of October 2, 2013 (the “Voting Agreement”), pursuant to which Mr. Wallen has agreed to vote shares of voting securities of the Company beneficially owned by him in favor of the Investors’ designees to the board of directors of the Company and with the Investors in connection with certain other matters.  Mr. Wallen has also agreed not to transfer shares of voting securities of the Company beneficially owned by him unless certain conditions specified in the Voting Agreement are satisfied.

In connection with entering into the Note Purchase Agreement and the Warrant and Preferred Stock Agreement, the Company entered into a Registration Rights Agreement, dated as of October 2, 2013, with the Investors, providing for, among other things, the registration of shares of Common Stock issuable upon exercise of the Warrants with the Securities and Exchange Commission.

The Company entered into and consummated the transactions contemplated by a Conversion and Preferred Stock Purchase Agreement dated October 2, 2013 (the “Conversion Agreement”) with Mr. Wallen and Langtry.  Pursuant to the terms of the Conversion Agreement, (a) Langtry was issued 12,047 shares of Series B Convertible Preferred Stock, with an aggregate stated value of $12,047,000, in exchange for the cancellation of all of the issued and outstanding shares of Series A Convertible Preferred Stock held by Langtry and (b) Mr. Wallen was issued 2,115 shares of Series B Convertible Preferred Stock, with an aggregate stated value of $2,115,000, in exchange for the cancellation of a promissory note payable to Mr. Wallen in the principal amount of $2,000,000, plus $114,986 of accrued and unpaid interest.

The Series B Convertible Preferred Stock is entitled to dividends at a rate of 9.5% per annum and, subject to certain limitations, is convertible into Common Stock at an initial conversion price of $0.50 per share of Common Stock. The holders of the Series B Convertible Preferred Stock are entitled to vote (on an as-converted basis), together with holders of Common Stock, as a single class with respect to all matters presented to holders of Common Stock.

Cubic Louisiana and WFEC entered into an Amended and Restated Credit Agreement dated October 2, 2013 (the “Credit Agreement”).  In conjunction with entering into the Credit Agreement, the Company assigned all of its previously held oil and gas interests that it held in Northwest Louisiana to Cubic Louisiana.  Pursuant to the terms of the Credit Agreement, the Company repaid the $5 million term loan payable to WFEC, and Cubic Louisiana assumed the remaining unpaid debt to WFEC, which amount was $20,865,110 as of that date.  That debt is reflected in a term loan bearing interest at the Wells Fargo Bank prime rate, plus 2%, per annum.  In the event that Cubic Louisiana does not have available cash to pay interest on the Credit Facility, accrued and unpaid interest may be paid in kind via additional promissory notes. Accrued and unpaid interest as of June 30, 2014 was paid in kind.  As part of the Credit Agreement, WFEC is providing a revolving credit facility in the amount of up to $10,000,000, bearing interest at the same rate, with all advances under that revolving credit facility to be made in the sole discretion of WFEC.  The indebtedness to WFEC

5

Table of Contents

pursuant to the Credit Agreement is secured by a first priority lien over all of the assets of Cubic Louisiana and Cubic Louisiana Holdings.  The other oil and gas properties of Cubic and its other subsidiaries, including the assets acquired from Gastar, Navasota and Tauren, as described above, do not secure the indebtedness under the Credit Agreement.  During fiscal 2014, Cubic Louisiana borrowed $4,015,826 against the WFEC revolving credit facility to finance participation in two new horizontal Haynesville wells drilled and completed by EXCO in our legacy Louisiana acreage. These borrowings leave a balance of $5,894,174 available to the Company under its revolving credit facility, subject to the approval of WFEC, and total debt outstanding of $24,880,936 with WFEC.

STRATEGY

As of June 30, 2014, our strategy with respect to our domestic exploration program seeks to maintain a balanced portfolio of drilling opportunities that range from lower risk, field extension wells to the smaller scale pursuit of Company appropriate higher risk, high reserve potential prospects.

Our East Texas assets are at the core of our current strategy, which we believe provide lower risk development opportunities and high yield opportunities.  The Company is exploring acquiring additional properties with this same development profile.

Additionally, our focus is on exploration opportunities that can benefit from advanced technologies, including 3-D seismic, designed to reduce risks and increase success rates. We develop prospects in-house with an affiliate and through strategic alliances with exploration companies that have expertise in specific target areas. In addition, we evaluate externally generated prospects and look to participate in certain of these opportunities to enhance our portfolio.

We are currently focusing our domestic exploration activities to develop and re-enter existing well bores, and re-complete existing well bores with respect to our recently acquired East Texas Basin assets; as well as developing our recently augmented leasehold interests in Louisiana.  East Texas Basin prospects have been developed from the top of the Cretaceous formation all the way to the bottom of the Deep Bossier Shale.  The various Cretaceous zones all have strong oil and liquids component that we believe will help the Company achieve its transition away from dry natural gas.  The high production of dry natural gas from the various Bossier sands have the opportunity to provide the Company an increase in short term cash flow, with reasonable out-of-pocket expenditures, even at current commodity prices, through the re-recompletion and work over of existing wells.  Prospects in our Louisiana leaseholds are focused on the Cotton Valley and the Haynesville Shale, but also include the Hosston; Gloyd; Pettet; Glen Rose and Paluxy.

The Company’s future results of operations and growth are substantially dependent upon (i) its ability to acquire or find new oil and gas properties, or successfully develop existing oil and gas properties, (ii) the prevailing prices for oil and gas, and (iii) our ability to refinance the Notes and remain a going concern. Numerous locations have been identified by third-party operators for additional drilling. If we are unable to economically complete additional producing wells, the Company’s oil and gas production, and its revenues, would likely decline rapidly as its reserves are depleted. In addition, oil and gas prices are dependent upon numerous factors beyond the Company’s control, such as economic, political, governmental, environmental and regulatory developments, as well as competition from other sources of energy. The oil and gas markets have historically been very volatile, and any further significant or extended decline in the price of gas would have a material adverse effect on the Company’s financial condition and results of operations, and could result in a further reduction in the carrying value of the Company’s proved reserves and adversely affect its access to capital.

6

Table of Contents

PRINCIPAL OIL AND GAS PROPERTIES

The following table summarizes certain information with respect to our principal areas of operation at June 30, 2014:

(a) Mcfe is defined as 6 Bbls of oil to 1 Mcf of natural gas.

As of June 30, 2014, our West Texas properties are situated in Eastland and Callahan Counties and represented an immaterial amount of reserves and are excluded from our SEC reserve report. Our East Texas properties are situated in Leon and Robertson Counties and contained approximately 66% of our total proved reserves, while our Louisiana properties that are situated in Caddo Parish and in DeSoto Parish contained approximately 34% of our total proved reserves. The West Texas properties owned as of June 30, 2014, consisted primarily of wells acquired by the Company in several transactions between 1991 and 2002 and through overriding royalty interests reserved in farm-out agreements in 1998 and 1999. The East Texas properties were acquired in October 2013. The vast majority of the legacy Louisiana acreage was acquired on or about October 1, 2004, January 11, 2005 and February 6, 2006.

Our net production for the fiscal year ended June 30, 2014 for all of the Company’s wells averaged approximately 11,080 Mcf of natural gas per day, 28 barrels of oil per day and 7 barrels of natural gas liquids per day as compared to approximately 3,127 Mcf of natural gas per day, 2 barrels of oil per day and 7 barrels of natural gas liquids per day in the fiscal year ended June 30, 2013.

7

Table of Contents

GAS GATHERING

Cubic has developed its infrastructure in Johnson Branch with approximately 16 miles of gathering lines and pipeline constructed for its currently producing wells and any further completions. In addition, a Johnson Branch tap, common point and compression facility were completed in November 2007 and are currently operational. The Company has also developed its infrastructure with approximately 7.8 miles of gathering lines and owns three taps in its Bethany Longstreet acreage.

In addition, for our East Texas properties, we have a midstream contract with Hilltop Resort GS, LLC that runs through October 31, 2024.  This contract with Hilltop Resort GS, LLC has a penalty provision expiring on October 31, 2014, if, for the previous quarter, an average of 50,000 Mcf/day is not sent through the pipelines.  Since the acquisitions on October 2, 2013, the Company has had to pay a quarterly penalty due to insufficient production. As of June 30, 2014, the Company accrued an obligation of $976,494 related to this contract.

MARKETING OF PRODUCTION

Crude Oil and Natural Gas

During fiscal 2014, our production consisted mainly of natural gas. During fiscal 2014, we marketed our production of natural gas that was produced from wells operated by our affiliate, Fossil Operating (“Fossil”), an entity controlled by Mr. Wallen, to four purchasers: (i) in Texas, BP Energy Company (“BP Energy”), Peninsula Pipelines (“Peninsula”) and Regency Energy Partners (“Regency”), and (ii) in Louisiana, Atmos Energy Marketing, LLC (“Atmos Energy”). We sell our affiliate-operated crude oil and natural gas liquids (“NGL”) production at or near the well-site; although in some cases it is gathered by us or others and delivered to a central point of sale. Our crude oil and condensate production is transported by truck or by pipeline and is marketed by BP Products North America (“BP Products”), Transoil Marketing, Inc. (“Transoil”), Eastex Crude Company (“Eastex”), and Martin Gas Sales (“Martin”). During fiscal 2014, all of our production was operated by Fossil and six third-party operators: BG, Chesapeake, EXCO, EP Energy, Goodrich and Indigo Minerals. Pursuant to the terms of our operating agreements, these third-party operators have the right to market our production from wells operated by them.  Purchases by BP Energy through Fossil totaled 81% of our total revenues for fiscal 2014. A significant portion of our production and our revenue is now generated by wells drilled and operated by non-affiliated third-party operators.

With respect to our production from Louisiana, we did not have any gas marketing agreements, commitments or contracts; we sell our crude oil, NGL and natural gas at the prevailing market prices.

As for our East Texas production, our hedging agreements with BP dictate that BP purchases all of our oil and natural gas through the calendar year 2016 for oil and through the calendar year 2018 for natural gas. We receive from BP a fixed price for the respective commodity up to certain volumes pursuant to the derivative contracts. We then receive a floating market price for volumes in excess of such amounts bound by the derivative contracts.

We believe we would be able to locate alternate purchasers in the event of the loss of any of these purchasers, and that any such loss would not have a material adverse effect on our financial condition or results of operations. Revenue totaled $15,849,482 for fiscal 2014 primarily from the sale of natural gas. Natural gas totaled $14,750,152 and represented 93%, oil totaled $977,880 and represented 6% and NGLs totaled $121,550 and represented 1% of our total oil and gas revenues, respectively for fiscal 2014.

Price Considerations

Natural gas and NGL prices in the geographical areas in which we operate are closely tied to established price indices which are heavily influenced by national and regional supply and demand factors and the futures price per MMbtu for natural gas delivered at Henry Hub, Louisiana established on the NYMEX (“NYMEX-Henry Hub”). At times, these indices correlate closely with the NYMEX-Henry Hub price, but often there are significant variances between the NYMEX-Henry Hub price and the indices used to price our

8

Table of Contents

natural gas. Except with respect to fixed pricing established pursuant to our derivative contracts, average natural gas prices received by us in each of our operating areas generally fluctuate with changes in these established indices. The average natural gas price per Mcf received by us in fiscal 2014 was $3.65 as compared to $3.21 in fiscal 2013. The average NGL price per barrel received by us in fiscal 2014 was $45.78 compared to $41.16 in fiscal 2013. Crude oil prices are established in a highly liquid, international market, with average crude oil prices that we receive generally fluctuating with changes in the futures price established on the NYMEX for West Texas Intermediate Crude Oil (“NYMEX-WTI”). The average crude oil price per barrel received by us in fiscal 2014 was $95.58 as compared to $90.00 in fiscal 2013.

OIL AND GAS RESERVES

The following tables set forth our proved developed and proved undeveloped reserves at June 30, 2014, the estimated future net cash flows from such proved reserves and the Standardized Measure of Discounted Future Net Cash Flows attributable to our proved reserves at June 30, 2014, 2013 and 2012:

(1)    The Standardized Measure of Discounted Future Net Cash Flows prepared by the Company represents the present value (using an annual discount rate of 10%) of estimated future net cash flows from the production of proved reserves, without giving effect to the future income tax expense. In accordance with guidelines of the SEC, prices used in this report are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the fiscal year. See “Note M - Oil and gas reserves information (unaudited)” in the Notes to the Financial Statements of the Company included elsewhere in this Report for additional information regarding the disclosure of the Standardized Measure information in accordance with the provisions of Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 932, Extractive Activities — Oil and Gas.

9

Table of Contents

As of June 30, 2014, we had a net increase in proved undeveloped reserves of 4,145,923 Mcfe.  This net increase includes (i) an increase of 4,706,416 Mcfe due to an “Extensions & Discoveries” gained through overall field development and activity and longer range Company planning, plus (ii) an increase of 24,280,352 Mcfe gained through the acquisition of the Tauren Louisiana Cotton Valley acreage and the existing East Texas proved undeveloped locations acquired from Gastar and Navasota partially offset by (iii) a downward “Revision of Previous Estimates” of 21,911,480 Mcfe due to wells not being drilled and dropping off of our drilling schedule and (iv) a downward revision of 2,929,365 Mcfe in estimated production from continuing proved undeveloped locations.

None of our reserves were converted from proved undeveloped reserves to proved developed reserves during the fiscal year ended June 30, 2014.  EXCO drilled and completed two new Haynesville Shale wells in fiscal 2014; however, neither of these drilling locations were proved undeveloped locations at June 30, 2013. The Company did not have any Haynesville Shale proved undeveloped locations at June 30, 2013.  These two EXCO wells are now proved producing reserves.

In compliance with Rule 4-10(a)(31)(ii) of Regulation S-X, the Company’s development plan for all reserves listed as proved undeveloped reserves includes only planned development and drilling within sixty months of initial disclosure of such reserves. All of these wells are expected to be operated by an affiliate of the Company.

The information set forth in this Annual Report relating to our proved reserves, estimated future net cash flows and present values is taken from reports prepared by Netherland, Sewell & Associates, Inc. (“NSAI”) for the fiscal years 2014 and 2013. The report for fiscal 2012 was prepared by NPC Engineering Group, Inc. (“NPC-ENG”), an independent petroleum engineering firm. The reservoir engineers at NSAI and NPC-ENG who oversaw the preparation of the reserve estimates for NSAI and NPC-ENG had Master’s of Science Degrees and are licensed as Professional Engineers in the State of Texas.  The estimates of the independent petroleum engineering firms were based upon review of production histories and other geological, economic, ownership and engineering data provided by the Company. Information with respect to our reserves in legacy Texas properties as of June 30, 2014, 2013 and 2012 was prepared in-house, was not reviewed by an independent engineering firm, and due to the immaterial size was not reported in our reserve report for the periods ended June 30, 2014, 2013 and 2012. Our internal geologist has a Master’s of Science Degree in Geology, is an American Association of Petroleum Geologists’ Certified Petroleum Geologist and has twenty-nine years of experience in the upstream oil and gas industry.  In accordance with guidelines of the SEC, prices used in this report are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the fiscal year.  For oil volumes, the average West Texas Intermediate posted price of $96.75 per barrel is adjusted by field for quality, transportation fees, and a regional price differential.  For gas volumes, the average Henry Hub spot price of $4.10 per MMbtu is adjusted by field for energy content, transportation fees, and a regional price differential.  All prices are held constant throughout the lives of the properties.  For the proved reserves, the average adjusted product prices for fiscal 2014 weighted by production over the remaining lives of the properties are $97.51 per barrel of oil, $47.66 per barrel of NGL, and $4.01 per Mcf of gas, but such costs do not include debt service or general and administrative expenses.

There are numerous uncertainties inherent in estimating oil and gas reserves and their values, including many factors beyond our control. The reserve data set forth in this Annual Report represents estimates only. Reservoir engineering is a subjective process of estimating the sizes of underground accumulations of oil and gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation, and judgment. As a result, estimates of different engineers, including those used by us, may vary. In addition, estimates of reserves are subject to revision based upon actual production, results of future development, exploitation and exploration activities, prevailing oil and gas prices, operating costs and other factors, which revisions may be material. Accordingly, reserve estimates are often different from the quantities of oil and gas that are ultimately recovered and are highly dependent upon the accuracy of the assumptions upon which they are based. There can be no assurance that these estimates are accurate predictions of our oil and gas reserves or their values. Estimates with respect to proved reserves that may be developed and produced in the future are often based upon volumetric calculations and upon analogy to similar types of reserves rather than actual production history. Estimates based on these methods are generally less reliable than those based on actual production

10

Table of Contents

history. Subsequent evaluation of the same reserves based upon production history will result in variations, which may be substantial, in the estimated reserves.

All reports were in accordance with generally accepted petroleum engineering and evaluation principles and definitions and guidelines established by the SEC. The technical persons responsible for preparing the reserve estimates presented herein meet the requirements regarding 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.

Our policies and practices regarding internal control over the estimating of reserves are structured to objectively and accurately estimate our oil and natural gas reserves quantities and present values in compliance with the SEC’s regulations and U.S. Generally Accepted Accounting Principles. We maintain an internal staff of petroleum engineers and geosciences professionals who work closely with our independent petroleum consultant to ensure the integrity, accuracy and timeliness of data furnished to our independent petroleum consultant in its reserves estimation process. Inputs to our reserves estimation process are based on historical results for production history, oil and natural gas prices, lease operating expenses, development costs, ownership interest and other required data. Our technical team meets regularly with representatives of our independent petroleum consultants to review properties and discuss methods and assumptions used in our independent petroleum consultant’s preparation of the year-end reserves estimates. While we have no formal committee specifically designated to review reserves reporting and the reserves estimation process, our senior management reviews and approves our independent petroleum engineer’s reserve report and any internally estimated significant changes to our proved reserves on a timely basis.

Costs Incurred

The following table shows certain information regarding the costs incurred by us in our property acquisition, development and exploratory activities during the periods indicated.

The Company received several credits from EXCO during fiscal 2013 thus creating negative total costs incurred for the year ended June 30, 2013.

11

Table of Contents

FISCAL 2014 DRILLING

During fiscal 2014, EXCO drilled and completed two wells, both of which are in the Haynesville Shale formation, in which the Company has interests.

We drilled or participated in the drilling of wells as set out in the table below for the periods indicated. The table was completed based upon the date drilling was completed. Other than the East Texas properties in Leon and Robertson Counties (the “Hilltop”), we did not acquire any wells during these periods. You should not consider the results of prior drilling activities as necessarily indicative of future performance, nor should you assume that there is necessarily any correlation between the number of productive wells drilled and the oil and natural gas reserves generated by those wells.

12

Table of Contents

NET PRODUCTION, SALES PRICES AND COSTS

The following table presents certain information with respect to production, prices and costs attributable to all oil and gas property interests owned by us for the fiscal years ended June 30, 2014, 2013 and 2012:

We had two fields that exceeded 15% of our total Proved Reserves as of June 30, 2014 and one field that exceeded 15% as of June 30, 2013. Our Johnson Branch field represented approximately 31%, 57% and 95% of our total Proved Reserves as of June 30, 2014, 2013 and 2012, respectively. Our Hilltop field represented 66% of our total Proved Reserves as of June 30, 2014.

The following table provides additional information related to production from each field in which we had proved reserves:

13

Table of Contents

PRODUCTIVE WELLS AND ACREAGE

Productive Wells

The following table sets forth our productive wells at June 30, 2014:

The East Texas properties had 18 wells producing oil during fiscal 2014. Eight of those wells were determined to be non-economical and probably will be scheduled for shut-in, leaving the Company 10 wells

14

Table of Contents

producing oil in economic quantities, at June 30, 2014. The Company had two new natural gas wells drilled and completed on our Louisiana acreage during fiscal 2014.

Acreage

The following table sets forth our undeveloped and developed gross and net leasehold acreage at June 30, 2014. The Louisiana undeveloped leasehold acreage is made up of alternate unit well sites that are part of our future drilling plan and currently have at least one well drilled and completed, so all of our acreage is held-by-production. Our East Texas acreage is approximately 40% held-by-production. Undeveloped acreage includes leased acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas, regardless of whether or not such acreage contains proved reserves.

As is customary in the industry, we generally acquire oil and gas acreage without any warranty of title except as to claims made by, through or under the transferor.  Although we have title to developed acreage examined prior to acquisition in those cases in which the economic significance of the acreage justifies the cost, there can be no assurance that losses will not result from title defects or from defects in the assignment of leasehold rights.

The Company engaged in the Cotton Valley vertical drilling program on its Northwest Louisiana acreage during 2005 through 2009.  In the last 24 months, it has been shown that a more economical way to exploit the Cotton Valley in and around our Northwest Louisiana acreage is to drill and complete well bores directed horizontally.  Generally, each square mile unit, or section, is economically capable of eight horizontally developed Cotton Valley well bores.  Based on current development in and around our acreage, we take a more conservative approach and project four horizontally developed Cotton Valley wells in each section.  Horizontal development of the Cotton Valley has achieved significantly higher ultimate recoveries of dry gas plus a good recovery of oil, while vertical development provides only a modest recovery of dry gas.  Therefore, our strategy with respect to development of our acreage in the Cotton Valley is through horizontal exploitation.

Substantially all of the Company’s acreage is prospective for horizontal Haynesville Shale development.  Generally, each section is economically capable of eight horizontally developed Haynesville Shale wells.  Unlike the Cotton Valley formation, which provides a good recovery of oil when exploited horizontally, the Hayesville Shale in our area produces dry gas. If natural gas prices increase, we expect horizontal Haynesville Shale development to increase.

There is one vertical Cotton Valley or Haynesville Shale well bore in each section.  Therefore, each section in which we hold an interest contains acreage that we expect to further develop.  Ultimately, the Company expects that there will be several Cotton Valley well bores drilled and completed horizontally in each of these sections.  However, the development of different formations in each of these sections, drilling multiple wells in certain formations in each section and employing horizontal completion techniques will allow for much greater future production from each of these sections than has been seen to-date.

On October 2, 2013, the Company purchased East Texas assets, well bores and infrastructure from Gastar and Navasota.  The East Texas assets provide drilling opportunities in the Cretaceous oily zones, the Cotton Valley Knowles, the middle Bossier and the Deep Bossier Reagan sands.  As of June 30, 2014, the Company only lightly engaged in re-completion activity in the middle Bossier zones in existing well bores.  Recent

15

Table of Contents

activity and recently completed 3-D seismic analysis has afforded the Company greater clarity as to the most advantageous opportunities to exploit the East Texas properties.  It is anticipated that in the upcoming fiscal year, the Company will exploit the oily Cretaceous zones, both through existing well bores and through new drilling, and exploit the deep Bossier formation and/or the Cotton Valley Knowles through new drilling.  This new drilling is expected to convert undeveloped acreage into developed acreage.

Lease Expirations

Our Louisiana acreage is all held-by-production. While our East Texas undeveloped lease acreage, excluding optioned acreage, will expire during the next four years, unless the leases are converted into producing units or extended prior to lease expiration. The following table sets forth the lease expirations as of June 30, 2014.

OPERATIONS

Oil and gas properties are customarily operated under the terms of a joint operating agreement, which provides for reimbursement of the operator’s direct expenses and monthly per well supervision fees. Per well supervision fees vary widely depending on the geographic location and producing formation of the well, whether the well produces oil or gas and other factors. As of June 30, 2014 approximately 18% of our oil and gas production, none of which totals 10% individually, were from wells operated by non-affiliated third-party operators and the balance of our production was operated by Fossil, an entity wholly owned by Mr. Wallen.

We have contract relationships with petroleum engineers, geologists and other operations and production specialists who believe the production rates and reserves will increase, which would lower the cost per Mcfe of operating our affiliated and non-affiliated third-party oil and gas properties.

EMPLOYEES

At November 4, 2014, the Company had twelve (12) full-time employees. We regularly use independent consultants and contractors to perform various professional services, including well-site supervision, design, construction, permitting and environmental assessment. We use independent contractors to perform field and on-site production operation services.

FACILITIES

The Company’s principal executive and administrative offices are located at 9870 Plano Road, Dallas, Texas, and are owned by an affiliate controlled by Mr. Wallen. Effective January 1, 2011, the Company signed a 2-year lease that charges the Company a monthly fee of $8,000 per month, which lease is currently on a month-to-month basis. The Company believes that there is other appropriate space available in the event the Company should terminate its current leasing arrangement, though the Company believes the monthly rental fee would likely exceed $8,000 per month.

16

Table of Contents

COMPETITION

The oil and gas business is a highly competitive industry.  Being a smaller player in our core positions, we are always susceptible to the influence of the larger companies operating in our primary areas of operations.  As of June 30, 2014, our acreage was being operated by affiliated and non-affiliated third-party operators. Approximately 40% of our acreage in Leon and Robertson Counties, Texas is held by production, with the balance of this acreage expected to be renewed or drilled to hold.  Additionally, there is open acreage in and around our Leon and Robertson County acreage position.  We are experiencing some competition in Leon and Robertson Counties with both renewing our current acreage position not held by production as well as entering into new leases; however, this has not had a material impact in our operations or our plans for development.

We have approximately 10,000 Cotton Valley acres and 4,000 Haynesville acres in Caddo and DeSoto Parishes in Northwest Louisiana.  Through an affiliate, we control operations on the vast majority of our Cotton Valley acreage in Northwest Louisiana.  In DeSoto and Caddo Parishes, Louisiana, our Bossier/Haynesville acreage is operated by BHP Billiton, EXCO, BG, Goodrich, Chesapeake, Indigo Minerals, and EP Energy.  This acreage is held by production, and we are not looking to expand our position in Northwest Louisiana.

In Eastland and Callahan Counties, Texas, we both operate through an affiliate and have farmout arrangements on properties that produce limited amounts of natural gas and oil condensate.  This is not a material asset for the Company.

REGULATION

Exploration and Production. The exploration, production and sale of oil and natural gas are subject to various types of local, state and federal laws and regulations. These laws and regulations govern a wide range of matters, including the drilling and spacing of wells, allowable rates of production, restoration of surface areas, plugging and abandonment of wells and requirements for the operation of wells. Our operations are also subject to various conservation requirements. These include the regulation of the size and shape of drilling and spacing units or proration units, the density of wells that may be drilled and the unitization or pooling of oil and natural gas properties. In this regard, Louisiana and Texas allow forced pooling or integration of tracts to facilitate exploration, while other states rely on voluntary pooling of lands and leases. 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 certain requirements regarding the ratability of production. All of these regulations may adversely affect the rate at which wells produce oil and natural gas and the number of wells we may drill. All statements in this report about the number of locations or wells reflect current laws and regulations.

Laws and regulations relating to our business frequently change, and future laws and regulations, including changes to existing laws and regulations, could adversely affect our business.

Environmental Matters. The discharge of oil, gas or other pollutants into the air, soil or water may give rise to liabilities to the government and third parties and may require us to incur costs to remedy or control such discharges. Natural gas, oil or other pollutants, including salt water brine, may be discharged in many ways, including from a well or drilling equipment at a drill site, leakage from pipelines or other gathering and transportation facilities, leakage from storage tanks and sudden discharges from damage or explosion at natural gas facilities or oil and natural gas wells. Discharged hydrocarbons may migrate through soil to water supplies or adjoining property, giving rise to additional liabilities.

A variety of federal and state laws and regulations govern the environmental aspects of natural gas and oil production, transportation and processing and may, in addition to other laws, impose liability in the event of discharges, whether or not accidental, failure to notify the proper authorities of a discharge, and other noncompliance with those laws. Compliance with such laws and regulations may increase the cost of oil and natural gas exploration, development and production; although we do not anticipate that compliance will

17

Table of Contents

have a material adverse effect on our capital expenditures or earnings. Failure to comply with the requirements of the applicable laws and regulations, by us or our third-party operators could subject us to substantial civil and/or criminal penalties and to the temporary or permanent curtailment or cessation of all or a portion of our operations.

The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the “superfund law,” imposes liability, regardless of fault or the legality of the original conduct, on some classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of a disposal site or sites where the release occurred and companies that dispose or arrange for disposal of the hazardous substances found at the time. Persons who are or were responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and 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. We could be subject to liability under CERCLA because our drilling and production activities generate relatively small amounts of liquid and solid waste, which could be subject to classification as hazardous substances under CERCLA.

The Resource Conservation and Recovery Act of 1976, as amended (“RCRA”), is the principal federal statute governing the treatment, storage and disposal of hazardous wastes. RCRA imposes stringent operating requirements, and liability for failure to meet such requirements, on a person who is either a “generator” or “transporter” of hazardous waste or an “owner” or “operator” of a hazardous waste treatment, storage or disposal facility. At various times in the past, proposals have been made to amend RCRA to rescind the exemption that excludes oil and natural gas exploration and production wastes from regulation as hazardous waste. Repeal or modification of the exemption by administrative, legislative or judicial process, or modification of similar exemptions in applicable state statutes, would increase the volume of hazardous waste we are required to manage and dispose of and would cause us to incur increased operating expenses.

The federal Water Pollution Control Act of 1972, as amended (“Clean Water Act”), and analogous state laws, impose restrictions and strict controls regarding the discharge of pollutants into certain water bodies. Pursuant to the Clean Water Act and analogous state laws, permits must be obtained to discharge pollutants into waters of the United States or, under state law, state surface or subsurface waters. Any such discharge of pollutants into regulated waters must be performed in accordance with the terms of a permit issued by the EPA or the analogous state agency. Spill prevention, control and countermeasure requirements under federal law require appropriate operating protocols including containment berms and similar structures to help prevent the contamination of regulated waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities or during construction activities.

Our third-party operators employ hydraulic fracturing techniques to stimulate natural gas production from unconventional geological formations, which entails the injection of pressurized fracturing fluids (consisting of water, sand and certain chemicals) into a well bore. The federal Energy Policy Act of 2005 amended the Underground Injection Control (“UIC”) provisions of the federal Safe Drinking Water Act (“SDWA”) to exclude hydraulic fracturing from the definition of “underground injection” under certain circumstances. However, the repeal of this exclusion has been advocated by certain advocacy organizations and others in the public. Legislation to amend the SDWA to repeal this exemption 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. Similar legislation could be introduced in the current session of Congress. Scrutiny of hydraulic fracturing activities continues in other ways, with the EPA having commenced a study of the potential environmental impacts of hydraulic fracturing. In December 2012, the EPA issued a progress report on its hydraulic fracturing study with final results now expected in 2016, after a two-year delay was announced by the EPA in June 2013. The agency also announced that one of its enforcement initiatives for 2014 to 2016 would be to focus on environmental compliance by the energy extraction sector. This study and enforcement

18

Table of Contents

initiative could result in additional regulatory scrutiny or further legislative or regulatory action regarding hydraulic fracturing or similar production operations that could make it difficult to perform hydraulic fracturing and increase our costs of compliance or significantly impact our business, results of operations, cash flows, financial position and future growth.

In addition, some states and localities have adopted, and others are considering adopting, regulations or ordinances that could restrict hydraulic fracturing in certain circumstances, or that would impose higher taxes, fees or royalties on natural gas production. Our operations are concentrated in Louisiana and Texas. We now have significant operations in Texas as well. We do not currently have operations on federal lands or in the states where the most stringent proposals have been advanced. However, if new federal or state laws or regulations that significantly restrict hydraulic fracturing are adopted, or if we acquire oil and gas properties in areas subject to those regulations, such legal requirements could result in delays, eliminate certain drilling and injection activities, make it more difficult or costly for us to perform fracturing and increase our costs of compliance and doing business. It is also possible that our drilling and injection operations could adversely affect the environment, which could result in a requirement to perform investigations or clean-ups or in the incurrence of other unexpected material costs or liabilities.

The Oil Pollution Act of 1990, as amended (“OPA”), which amends the Clean Water Act, establishes strict liability for owners and operators of facilities that are the site of a release of oil into waters of the United States. The OPA and its associated regulations impose a variety of requirements on responsible parties related to the prevention of oil spills and liability for damages resulting from such spills. A “responsible party” under the OPA includes owners and operators of certain onshore facilities from which a release may affect regulated waters.

The federal Clean Air Act, as amended (“Clean Air Act”), and state air pollution permitting laws, restrict the emission of air pollutants from many sources, including processing plants and compressor stations and potentially from our drilling and production operations, and as a result affects oil and natural gas operations. We may be required to incur compliance costs or capital expenditures for existing or new facilities to remain in compliance. In addition, more stringent regulations governing emissions of air pollutants, including greenhouse gases such as methane (a component of natural gas) and carbon dioxide are being developed by the federal government, and may increase the costs of compliance for some facilities or the cost of transportation or processing of produced oil and gas which may affect our operating costs. Obtaining permits has the potential to delay the development of oil and natural gas projects. While we may be required to incur certain capital expenditures in the next few years for air pollution control equipment or other air emissions-related issues, we do not believe, based on current law, that such requirements will have a material adverse effect on our operations.

In response to findings that emissions of carbon dioxide, methane and other greenhouse gases (“GHG”), from industrial and energy sources contribute to increases of carbon dioxide levels in the earth’s atmosphere and oceans, effects on climate, and other environmental effects and therefore present an endangerment to public health and the environment, the EPA has adopted various regulations under the Clean Air Act, addressing emissions of greenhouse gases that may affect the oil and gas industry. On November 8, 2010, the EPA finalized rules expanding its Mandatory Greenhouse Gas Reporting Rule, originally promulgated in October 2009, to be applicable to the oil and natural gas industry, including certain onshore oil and natural gas production activities, which may affect certain of our existing or future operations and require the inventory and reporting of emissions. In addition, the EPA has taken the position that existing Clean Air Act provisions require an assessment of greenhouse gas emissions within the permitting process for certain large new or modified stationary sources under the EPA’s Prevention of Significant Deterioration and Title V permit programs, effective as of 2011. On April 17, 2012, the EPA issued final rules to subject oil and natural gas operations to regulation under the New Source Performance Standards (“NSPS”) and National Emission Standards for Hazardous Air Pollutants (“NESHAPS”) programs under the Clean Air Act, and to impose new and amended requirements under both programs. The EPA rules include NSPS standards for completions of hydraulically fractured natural gas wells. Before January 1, 2015, these standards require owners/operators to reduce volatile organic compound (“VOC”) emissions from natural gas not sent to the gathering line during well completion either by flaring using a completion combustion device or by capturing

19

Table of Contents

the natural gas using green completions with a completion combustion device. Beginning January 1, 2015, operators must capture the natural gas and make it available for use or sale, which can be done through the use of green completions. The standards are applicable to new hydraulically fractured wells and also existing wells that are refractured. Further, the finalized regulations also establish specific new requirements, which became effective in 2012, for emissions from compressors, controllers, dehydrators, storage tanks, natural gas processing plants and certain other equipment. These rules may require changes to our operations, including the installation of new equipment to control emissions. We are currently evaluating the effect these rules will have on our business.

We are unable to assure that more stringent laws and regulations protecting the environment will not be adopted and that we will not incur material expenses in complying with them in the future. For example, although federal legislation regarding the control of emissions of GHG for the present, appears unlikely, the EPA has been implementing regulatory measures under existing Clean Air Act authority and some of those regulations may affect our operations. These GHG regulations could require us to incur increased operating costs and could have an adverse effect on demand for the oil and natural gas we produce.

Although this rule does not limit the amount of GHGs that can be emitted, it requires the operator of the wells to incur costs to monitor, record keep and report GHG emissions associated with our operations. In addition, some states have considered, and notably California has adopted, a state specific GHG regulatory program that may limit GHG emissions or may require costs in association with the control of GHG emissions.

The federal Endangered Species Act, as amended (“ESA”), and comparable state laws, may restrict activities that affect endangered and threatened species or their habitats. Some of our facilities may be located in areas that are designated as habitat for endangered or threatened species. The designation of previously unidentified endangered or threatened species could cause us to incur additional costs or become subject to operating restrictions or bans in the affected areas.

We are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act, as amended (“OSHA”), and comparable state laws, whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. These laws and provisions of CERCLA require reporting of spills and releases of hazardous chemicals in certain situations.

We do not believe that our environmental, health and safety risks will be materially different from those of comparable U.S. companies in the oil and natural gas industry. Nevertheless, there can be no assurance that such environmental, health and safety laws and regulations will not result in a curtailment of production or material increase in the cost of production, development or exploration or otherwise adversely affect our capital expenditures, financial condition and results of operations.

In addition, because we have acquired and may acquire interests in properties that have been operated in the past by others, we may be liable for environmental damage, including historical contamination, caused by such former operators. Additional liabilities could also arise from continuing violations or contamination not discovered during our assessment of the acquired properties.

Natural Gas Marketing and Transportation. Our sales of natural gas are affected by the availability, terms and cost of transportation. The price and terms for access to pipeline transportation are subject to extensive federal and state regulation. From 1985 to the present, several major regulatory changes have been implemented by Congress and the Federal Energy Regulatory Commission (“FERC”). The FERC regulates interstate natural gas transportation rates, and terms and conditions of service, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas. Since 1985, the FERC has endeavored to make natural gas transportation more accessible to natural gas buyers and sellers on

20

Table of Contents

an open and non-discriminatory basis. Beginning in 1992, the FERC issued a series of orders, beginning with Order No. 636, to implement its open access policies. As a result, the interstate pipelines’ traditional role of providing the sale and transportation of natural gas as a single service has been eliminated and replaced by a structure under which pipelines provide transportation and storage service on an open access basis to others who buy and sell natural gas. Although the FERC’s orders do not directly regulate natural gas producers, they are intended to foster increased competition within all phases of the natural gas industry.

In addition, the FERC is continually proposing and implementing new rules affecting segments of the natural gas industry, most notably interstate natural gas transmission companies that remain subject to FERC’s jurisdiction. These initiatives may also affect the intrastate transportation of gas under certain circumstances. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry and these initiatives generally reflect more light-handed regulation.

The natural gas industry historically has been very heavily regulated. Therefore, we cannot provide any assurance that the less stringent regulatory approach established by the FERC under Order No. 637 will continue. However, we do not believe that any action taken will affect us in a way that materially differs from the way it affects other natural gas producers, gatherers and marketers with which we compete.

The price at which we sell natural gas is not currently subject to federal rate regulation and, for the most part, is not subject to state regulation. However, with regard to our physical sales of these energy commodities, we are required to observe anti-market manipulation laws and related regulations enforced by the FERC, the Commodity Futures Trading Commission (“CFTC”) and/or the Federal Trade Commission. Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third party damage claims by, among others, sellers, royalty owners and taxing authorities.

Crude Oil Marketing and Transportation. Our sales of crude oil and condensate are currently not regulated and are made at market prices. Nevertheless, Congress could reenact price controls in the future.

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, we believe that the regulation of oil transportation rates will not affect our operations in any way that is materially different from those of our competitors who are similarly situated.

Further, 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 similarly situated shippers requesting service on the same terms and under the same rates. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our similarly situated competitors.

GLOSSARY OF CERTAIN OIL AND GAS TERMS

The following are abbreviations and definitions of terms commonly used in the oil and gas industry, many of which are used in this Report.

“Bbl” means a barrel of 42 U.S. gallons, used herein in reference to oil or other liquid hydrocarbons.

“Bcf” means one billion cubic feet.

“Bcfe” means Bcf of natural gas equivalent; determined using the ratio of one Bbl of oil or condensate to six Mcf of natural gas.

“Btu” means British thermal unit, which means the quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

21

Table of Contents

“Casing” means a type of pipe that is used for encasing a smaller diameter carrier pipe for installation in a well.  Casing is used to send off fluids from the hole or keep a hole from caving in.

“Completion” means the installation of permanent equipment for the production of oil or gas.

“Compressor Station” means a facility in which the pressure of natural gas is raised to facilitate its transmission through pipelines.

“Condensate” means hydrocarbons naturally occurring in the gaseous phase in a reservoir that condense to become a liquid at the surface due to the change in pressure and temperature.

“Cubic Foot” means the volume of gas that fills one cubic foot of space under standard temperature and pressure conditions.  Standard pressure is 14.73 psi and standard temperature is 60 degrees Fahrenheit.

“Developed Acreage” means the number of acres that are allocated or assignable to producing wells or wells capable of production.

“Development Drilling” or “Development Well” means a well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

“Dry Hole” or “Dry Well” means a well found to be incapable of producing hydrocarbons in sufficient quantities to justify completion as an oil and gas well.

“Estimated Future Net Cash Flows” means estimated future gross cash flows to be generated from the production of proved reserves, net of estimated production, future development costs, and future abandonment costs, using prices and costs in effect as of the date of the report or estimate, without giving effect to non-property related expenses such as general and administrative expenses, debt service and future income tax expense or to depreciation, depletion and amortization.

“Exploration” is the act of searching for potential sub-surface reservoirs of gas or oil.  Methods include the use of magnetometers, gravity meters, seismic exploration, surface mapping, and the drilling of exploratory test wells (known as “wildcats”).

“Exploratory Drilling” or “Exploratory Well” means a well drilled to find and produce oil or gas reserves not classified as proved, to find a new production reservoir in a field previously found to be productive of oil or gas in another reservoir or to extend a known reservoir.

“Fracture Stimulation”  means a stimulation treatment routinely performed involving the injection of water, sand and chemicals under pressure to stimulate hydrocarbon production in low-permeability reservoirs.

“Farm-In” or “Farm-Out” means an agreement pursuant to which the owner of a working interest in an oil and gas lease assigns the working interest or a portion thereof to another party who desires to drill on the leased acreage. Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage. The assignor usually retains a royalty or reversionary interest in the lease. The interest received by an assignee is a “farm-in” and the assignor issues a “farm-out.”

“Finding and Development Costs” means the total costs incurred for exploration and development activities (excluding exploratory drilling in progress and drilling inventories), divided by total proved reserve additions. To the extent any portion of the proved reserve additions consist of proved undeveloped reserves; additional costs would have to be incurred in order for such proved undeveloped reserves to be produced. This measure may differ from the measure used by other oil and natural gas companies.

“Gas” means natural gas.

22

Table of Contents

“Full Cost Pool”  The full cost pool consists of all costs associated with property acquisition, exploration, and development activities for a company using the full cost method of accounting. Additionally, any internal costs that can be directly identified with acquisition, exploration and development activities are included. Any costs related to production, general corporate overhead or similar activities are not included.

“Gathering System” means a system of pipelines, compressor stations and any other related facilities that gathers natural gas from a supply region and transports it to the major transmission systems.

“Gross” when used with respect to acres or wells, means the total acres or wells in which we have a working interest.

“Held-by-production”  A provision in an oil, gas and mineral lease that perpetuates a company’s right to operate a property or concession as long as the property or concession produces a minimum paying quantity of oil or gas.

“Horizontal Drilling” means drilling a well that deviates from the vertical and travels horizontally through a prospective reservoir.

“Horizontal Wells”  Wells which are drilled at angles greater than 70 degrees from vertical.

“Hydrocarbons” means an organic chemical compound of hydrogen and carbon.  Hydrocarbons are a large class of liquid, solid or gaseous organic compounds, which are the basis of almost all petroleum products.

“Infill drilling” means drilling of a well between known producing wells to better exploit the reservoir.

“Initial production rate” means generally, the maximum 24 hour production volume from a well.

“Lease” means a formal agreement between two or more parties where the owner of the land grants another party the right to drill and produce hydrocarbons in exchange for payment.

“Mcf” means one thousand cubic feet.

“Mmcf/d” means one million cubic feet of natural gas per day.

“Mcfe” means Mcf of natural gas equivalent; determined using the ratio of one Bbl of oil or condensate to six Mcf of natural gas.

“MMbtu” means one million Btus.

“MMcf” means one million cubic feet.

“MMcfe” means MMcf of natural gas equivalent, determined using the ratio of one Bbl of oil or condensate to six Mcf of natural gas.