UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended ~~June~~September 30, 2013

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

For the transition period from ______________to ______________

Commission File Number 000-52738

CROSS BORDER RESOURCES, INC.

(Exact Name of Registrant as Specified in Its Charter)

Nevada	98-0555508
(State or Other Jurisdiction of Incorporation or Organization)	(I.R.S. Employer Identification No.)

2515 McKinney Avenue, Suite 900 Dallas, TX	75201
(Address of Principal Executive Offices)	(Zip Code)

(210) 226-6700

(Registrant’s Telephone Number, Including Area Code)

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

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

Common Stock, par value $.001

(Title of class)

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.

x Yes o No

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).

x Yes o No

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

Large accelerated filer o	Accelerated filer o
Non-accelerated filer o (Do not check if a smaller reporting company)	Smaller reporting company x

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

o Yes x No

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date:

As of ~~August~~November 1922, 2013, the Registrant had 17,336,226 shares of common stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

None.

TABLE OF CONTENTS

PART I. FINANCIAL INFORMATION

Item 1.	Financial Statements	3
	Unaudited Balance Sheets as of June 30, 2013 and December 31, 2012	3
	Unaudited Balance Sheets as of September 30, 2013 and December 31, 2012	3
	Unaudited Statements of Operations for the Three and Six Months Ended June 30, 2013 and June 30, 2012	5
	Unaudited Statements of Operations for the Three and Nine Months Ended September 30, 2013 and September 30, 2012	5
	Unaudited Statements of Cash Flows for the Six Months Ended June 30, 2013 and June 30, 2012	7
	Unaudited Statements of Cash Flows for the Nine Months Ended September 30, 2013 and September 30, 2012	7
	Unaudited Notes to Financial Statements	8
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	1918
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	2826
Item 4.	Controls and Procedures	2826
PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	2927
Item 1A.	Risk Factors	2927
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	2927
Item 3.	Defaults Upon Senior Securities	2927
Item 4.	Mine Safety Disclosures	2927
Item 5.	Other Information	2927
Item 6.	Exhibits	3129

PART I. FINANCIAL INFORMATION

Item 1. ~~Fnancial~~Financial Statements

Cross Border Resources, Inc.

Balance Sheets

	June 30,		December 31,
	September 30,		December 31,
	2013		2012
ASSETS
Current Assets
Cash and Cash Equivalents	$	72978,~~809~~614	$	241,561
Accounts Receivable – Oil and Natural Gas Sales		43,~~041~~054,~~776~~674		3,194,725
Prepaid Expenses & Other Current Assets		~~345~~93,~~436~~729		465,223
Derivative Asset - Current Portion		~~109,042~~—		235,825
Current Tax Asset		19,600		21,737
Total Current Assets		4,~~588~~146,~~663~~617		4,159,071
Oil and Gas Properties		5455,~~125~~245,~~148~~214		48,248,378
Less: Accumulated Depletion, Amortization, and Impairment		(1819,~~804~~881,~~212~~867)		(16,018,892	)
Net Oil and Gas Properties		35,~~320~~363,~~936~~347		32,229,486
Other Assets
Other Property and Equipment, net of Accumulated Depreciation of $86,509 and $77,190 in 2013 and 2012, respectively		43,960		53,280
Other Property and Equipment, net of Accumulated Depreciation of $91,169 and $77,190 in 2013 and 2012, respectively		39,301		53,280
Deferred financing costs, net of accumulated amortization of $3,700 and $113,581 in 2013 and 2012, respectively		23,925		101,045
Restricted Cash		206,087		—
Derivative Asset, net of Current Portion		46,702		54,963
Deferred financing costs, net of accumulated amortization of $8,844 and $113,581 in 2013 and 2012, respectively		102,175		101,045
Derivative Asset, net of Current Portion		3,504		54,963
Other Assets		54,324		54,324
Total Other Assets		~~168~~405,~~911~~391		263,612
TOTAL ASSETS	$	4039,~~078~~915,~~510~~355	$	36,652,169

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

	June 30,			December 31,
	September 30,			December 31,
	2013			2012
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts Payable - Trade	$	3901,~~491,850~~996		$	4,226,547
Accounts Payable – Related Party		~~409~~1,~~391~~830,006			215,495
Interest Payable		—			130,929
Accrued Expenses & Other Payables		20203,~~510~~802			61,065
Notes Payable - Current		—			764,278
Creditors Payable - Current Portion		—			758,167
Environmental Liability – Current Portion		1,420,354			860,000
Derivative Liability		95,896
Asset Retirement Obligation – Current Portion		542,493			452,013
Environmental Liability – Current Portion		1,043,416			860,000
Asset Retirement Obligation – Current Portion		455,515			452,013
Deferred Tax Liability		19,600			21,737
Total Current Liabilities		54,~~904~~550,~~148~~231			7,490,231
Non-Current Liabilities
Asset Retirement Obligations		2,~~856~~998,~~653~~267			2,865,345
Deferred Income Tax Liability		—			—
Environmental Liability, Net of Current Portion		~~667~~1,~~804~~043,417			1,240,000
Line of Credit		12,200,000			8,750,000
Creditors Payable, Net of Current Portion		—			594,616
Total Non-Current Liabilities		1516,~~724~~241,~~457~~684			13,449,961
Total Liabilities		2120,~~628~~791,~~605~~915			20,940,192
Commitments & Contingencies (Note 10)
Stockholders’ Equity
Common Stock ($0.001 par value; 99,000,000 shares authorized and 17,336,226 issued and outstanding as of June 30, 2013 and 16,301,946 as of December 31, 2012)		17,336			16,302
Common Stock ($0.001 par value; 99,000,000 shares authorized and 17,336,226 issued and outstanding as of September 30, 2013 and 16,301,946 as of December 31, 2012)		17,336			16,302
Additional Paid in Capital		33,462,473			32,770,540
Accumulated Deficit		(1514,~~029~~356,~~904~~369	)		(17,074,865	)
Total Stockholders’ Equity		1819,~~449~~123,~~905~~440			15,711,977
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	4039,~~078~~915,~~510~~355		$	36,652,169

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

Cross Border Resources, Inc.

Statements of Operations

	Three Months Ended June 30,
	Three Months Ended September 30,
	2013			2012
Revenues
Oil and gas sales	$	3,~~461~~430,~~249~~100		$	42,~~147~~811,~~645~~224
Other – deferred revenue		—			—
Total revenues		3,~~461~~430,~~249~~100			42,~~147~~811,~~645~~224
Expenses:
Operating costs		~~891~~532,~~666~~443			~~243~~715,~~847~~012
Natural gas marketing and transportation expenses		4216,~~572~~750			—
Production taxes		~~254~~388,~~241~~546			~~368~~218,~~587~~552
Depreciation, depletion, amortization, and Impairment		1,~~679~~082,~~138~~315			~~991~~1,~~938~~339,554
Impairment of oil & gas properties		—			~~1,775,796~~—
Accretion expense		36,723			29,353
Loss on sale of oil and gas properties		—			47,607
General and administrative		263,407			1,561,920
Accretion expense		37,982			17,905
Total expense		3,167,747			4,971,441
General and administrative		251,551			500,975
Gain from operations		293,502			(823,796	)
Total expense		2,309,587			2,839,605
Gain (loss) from operations		1,120,513			(28,381	)
Other income (expense):
Gain on derivatives		107,635			1,435,824
Gain (loss) on derivatives		(304,858	)		(447,010)
Interest expense		(~~160~~142,~~853~~122	)		(~~137~~135,~~169~~112	)
Miscellaneous other income		(—	)		393
Miscellaneous other income (expense)		—			4,530
Total other income (expense)		(53446,~~218)~~980	)		1(577,~~299,048~~592)
Income before income taxes		~~240~~673,~~284~~533			~~475~~(605,~~252~~973)
Current tax benefit		(—	)		61(194,~~932~~828)
Deferred tax expense		—			~~(61~~194,~~932~~828	)
Income tax expense		—			—
Net income	$	240,284		$	475,252
Net income (loss)	$	673,533		$	(605,973)
Net income per share:
Net income (loss) per share:
Basic	$	0.01		$	0.03
Basic and diluted	$	0.04		$	(0.04)
Fully diluted	$	0.01		$	0.03
Weighted average shares outstanding:
Basic		16,821,943			16,151,946
Basic and diluted		17,336,226			16,151,946
Fully diluted		16,821,943			16,151,946

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

Cross Border Resources, Inc.

Statements of Operations

	Six Months Ended June 30,
	Nine Months Ended September 30,
	2013			2012
Revenues
Oil and gas sales	$	610,~~794~~224,~~047~~147		$	710,~~721~~532,~~391~~615
Other – deferred revenue		—			32,479
Total revenues		610,~~794~~224,~~047~~147			710,~~753~~565,~~870~~094
Expenses:
Operating costs		1,~~339~~865,~~097~~199			~~980~~1,~~228~~695,239
Natural gas marketing and transportation expenses		4965,~~140~~890			—
Production taxes		~~388~~783,~~255~~141			~~528~~747,~~958~~510
Depreciation, depletion, amortization, and Impairment		23,~~794~~876,~~639~~954			12,~~536~~875,~~058~~612
Impairment of oil & gas properties		—			1,775,796
Accretion expense		71,702			34,241
Loss on sale of oil & gas properties					47,607
General and administrative		596,128			2,232,990
Accretion expense		109,684			52,146
Total expense		5,238,961			7,088,271
General and administrative		847,677			2,733,965
Gain from operations		1,555,086			665,599
Total expense		7,548,545			9,927,875
Gain from operations		2,675,602			637,219
Other income (expense):
Bond issuance amortization		—			(159,554	)
Gain (loss) on derivatives		(22327,~~557~~415	)		~~961~~514,~~911~~901
Gain on settlement of debt		858,452			—
Interest expense		(~~346~~488,~~022~~144	)		(~~268~~404,~~927~~039	)
Miscellaneous other income		—			38,~~872~~402
Total other income (expense)		~~489~~42,~~873~~893			~~537~~(40,~~302~~290)
Income before income taxes		2,~~044~~718,~~959~~495			1596,~~202,901~~929
Current tax benefit		(—	)		~~(180~~89,~~519~~973	)
Deferred tax expense		—			~~180~~(89,~~519~~973	)
Income tax expense		—			—
Net income	$	2,~~044~~718,~~959~~495		$	1596,~~202,901~~929
Net income per share:
Basic	$	0.12		$	0.07
Basic and diluted	$	0.16		$	0.04
Fully diluted	$	0.12		$	0.07
Weighted average shares outstanding:
Basic		16,999,085			16,151,946
Basic and diluted		17,112,700			16,151,946
Fully diluted		16,999,085			16,151,946

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

Cross Border Resources, Inc.

Statements of Cash Flows

	Six Months Ended June 30,
	Nine Months Ended September 30,
	2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	2,~~044~~718,~~960~~495		$	1596,~~202,901~~929
Adjustments to reconcile net income (loss) to cash used by operating activities:
Adjustments to reconcile net income to cash used by operating activities:
Depreciation, depletion, amortization, and impairment		23,~~803~~876,~~959~~954			34,~~311~~619,~~854~~650
Settlement of environmental liability		(11,842	)		—
Gain on Settlement of Creditors Liability		(350,800)			—
Accretion of asset retirement obligations		71,702			34,241
Gain on Conversion of Notes		(485,416)			—
Amortization of debt discount and deferred financing costs		77,120			218,631
Settlement of environmental liability		(13,167	)		—
Change in derivative instruments		135,044			—
Accretion of asset retirement obligations		109,684			52,146
(Gain) loss on disposition of assets					47,607
Amortization of debt discount and deferred financing costs		(1,130	)		218,631
Change in derivative instruments					(406,485)
Changes in operating assets and liabilities:
Accounts receivable		~~(847~~140,051	)		( 1,~~643~~228,~~247~~431	)
Prepaid expenses and other current assets		~~119~~369,~~787~~380			1,~~105~~333,~~082~~249
Accounts payable		~~445~~(781,~~491~~646	)		~~293~~314,~~588~~870
Accounts payable – related party		—			—370,578
Change of Control Liability					623,347
Restricted Cash		(206,087	)		—
Accrued expenses		~~652~~142,~~412~~738			~~117~~(532,~~229~~506)
Derivative asset/liability		—383,180			~~(941,045~~—	)
Deferred income tax		—			—
Deferred revenue		—			(32,479	)
Interest payable		(130,929	)		—
Other current liabilities		—			503,773
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES		5,360,653			4,290,102
NET CASH PROVIDED BY OPERATING ACTIVITIES		5,902,236			5,857,532
CASH FLOWS USED IN INVESTING ACTIVITIES
Capital expenditures - oil and gas properties		(67,~~862~~954,~~343~~272	)		(710,~~906~~913,~~200~~119	)
Proceeds from disposal of oil and gas properties		—			—2,250,000
Capital expenditures - other assets		—			—
NET CASH USED IN INVESTING ACTIVITIES		(67,~~862~~954,~~343~~272	)		(78,~~906~~663,~~200~~119	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from issuance of common stock, net of expenses		—			—
Borrowings on line of credit		12,200,000			7,119,000
Payments on line of credit		(8,750,000	)		—(750,000)
Payments to purchase stock options					—
Proceeds from renewing notes		—			—
Repayments of notes payable		(764,278	)		—
Repayments of bonds		—			(3,395,000	)
Repayments to creditors		(1660,~~352,783~~911	)		(186,761	)
Deferred financing costs		—			—
NET CASH PROVIDED BY FINANCING ACTIVITIES		2,789,089			2,787,239
NET CASH PROVIDED BY FINANCING ACTIVITIES		1,332,939			3,537,239
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		737,053			(18,348	)
NET DECREASE IN CASH AND CASH EQUIVALENTS		(168,751	)		(78,861	)
Cash and cash equivalents, beginning of period		241,561			472,967
Cash and cash equivalents, end of period	$	72978,~~810~~614		$	~~394~~454,~~106~~619
Supplemental disclosures of cash flow information:
Interest paid	$	~~241~~398,~~277~~040		$	~~171~~309,~~993~~631
Income taxes paid	$	—		$	—
NON-CASH TRANSACTIONS
Oil and natural gas properties included in accounts payable	$	0		$	1132,~~220,904~~915
Oil and natural gas properties included in Accrued Expenses	$	0		$	~~1,266,566~~—
Issuance of common stock to settle liability	$	0(692,967)		$	—
Additions of ARO	$	026,740		$	—

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

Cross Border Resources, Inc.

Notes to Financial Statements

1.	Organization

Nature of Operations

The Company is an independent natural gas and oil company engaged in the exploration, development, exploitation, and acquisition of natural gas and oil reserves in North America. The Company’s primary area of focus is the State of New Mexico, particularly southeastern New Mexico. The Company has two wholly-owned subsidiaries, which are inactive: Doral West Corporation and Pure Energy Operating, Inc, and accordingly are not consolidated in these financial statements.

2.	Going Concern

These ~~consolidated~~ financial statements have been prepared on the basis of accounting principles applicable to a going concern. These principles assume that the Company will be able to realize its assets and discharge its obligations in the normal course of operations for the foreseeable future.

At ~~June~~September 30, 2013, the Company had a working capital deficit of $1403,~~315,485~~614 and outstanding debt (consisting of a line of credit) of $12,200,000. The accompanying financial statements do not include any adjustments to reflect the possible future effects on the recoverability and classification of assets or the amounts and classifications of liabilities that may result from the possible inability of the Company to continue as a going concern.

3.	Summary of Significant Accounting Policies

Reclassification

Certain amounts have been reclassified to conform with the current period presentation. The amounts reclassified did not have an effect on the Company’s results of operations or stockholders’ equity.

Cash and cash equivalents

The Company considers all highly liquid debt instruments purchased with an original maturity of three months or less to be cash equivalents. At times, the amount of cash and cash equivalents on deposit in financial institutions exceeds federally insured limits. The Company monitors the soundness of the financial institutions and believes the Company’s risk is negligible.

Financial instruments

The carrying amounts of financial instruments, including cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities and long-term debt, approximate fair value as of ~~June~~September 30, 2013 and December 31, 2012.

Oil and natural gas properties

The Company follows the successful efforts method of accounting for its oil and natural gas producing activities. Costs to acquire mineral interests in oil and natural gas properties and to drill and equip development wells and related asset retirement costs are capitalized. Costs to drill exploratory wells are capitalized pending determination of whether the wells have proved reserves. If the Company determines that the wells do not have proved reserves, the costs are charged to expense. There were no exploratory wells capitalized pending determination of whether the wells have proved reserves at December 31, 2012 or ~~June~~September 30, 2013. Geological and geophysical costs, including seismic studies and costs of carrying and retaining unproved properties, are charged to expense as incurred. The Company capitalizes interest on expenditures for significant exploration and development projects that last more than six months while activities are in progress to bring the assets to their intended use. Through ~~June~~September 30, 2013, the Company had capitalized no interest costs because its exploration and development projects generally lasted less than six months. Costs incurred to maintain wells and related equipment are charged to expense as incurred.

On the sale or retirement of a complete unit of a proved property, the cost and related accumulated depreciation, depletion and amortization are eliminated from the property accounts, and the resultant gain or loss is recognized. On the retirement or sale of a partial unit of proved property, the cost is charged to accumulated depreciation, depletion and amortization, with a resulting gain or loss recognized in income.

Capitalized amounts attributable to proved oil and natural gas properties are depleted by the unit-of-production method over proved reserves using the unit conversion ratio of six Mcf of gas to one barrel of oil equivalent (“Boe”). The ratio of six Mcf of natural gas to one Boe is based upon energy equivalency, rather than price equivalency. Given current price differentials, the price for a Boe for natural gas differs significantly from the price for a barrel of oil.

It is common for operators of oil and natural gas properties to request that joint interest owners pay for large expenditures, typically for drilling new wells, in advance of the work commencing. This right to call for cash advances is typically found in the operating agreement that joint interest owners in a property adopt. The Company records these advance payments in prepaid and other current assets and release this account when the actual expenditure is later billed to it by the operator.

On the sale of an entire interest in an unproved property for cash or cash equivalents, gain or loss on the sale is recognized, taking into consideration the amount of any recorded impairment if the property had been assessed individually. If a partial interest in an unproved property is sold, the amount received is treated as a reduction of the cost of the interest retained.

Impairment of long-lived assets

The Company evaluates its long-lived assets for potential impairment in their carrying values whenever events or changes in circumstances indicate such impairment may have occurred. Oil and natural gas properties are evaluated for potential impairment by field. Other properties are evaluated for impairment on a specific asset basis or in groups of similar assets, as applicable. An impairment on proved properties is recognized when the estimated undiscounted future net cash flows of an asset are less than its carrying value. If an impairment occurs, the carrying value of the impaired asset is reduced to its estimated fair value, which is generally estimated using a discounted cash flow approach. If the results of an assessment indicate that the properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized.

Unproved oil and natural gas properties do not have producing properties. As reserves are proved through the successful completion of exploratory wells, the cost is transferred to proved properties. The cost of the remaining unproved basis is periodically evaluated by management to assess whether the value of a property has diminished. To do this assessment, management considers estimated potential reserves and future net revenues from an independent expert, the Company’s history in exploring the area, the Company’s future drilling plans per its capital drilling program prepared by the Company’s reservoir engineers and operations management and other factors associated with the area. Impairment is taken on the unproved property cost if it is determined that the costs are not likely to be recoverable. The valuation is subjective and requires management to make estimates and assumptions which, with the passage of time, may prove to be materially different from actual results.

Revenue and accounts receivable

The Company recognizes revenue for its production when the quantities are delivered to, or collected by, the purchaser. Prices for such production are generally defined in sales contracts and are readily determinable based on certain publicly available indices. All transportation costs are included in lease operating expense.

Accounts receivable—oil and natural gas sales consist of uncollateralized accrued revenues due under normal trade terms, generally requiring payment within 30 to 60 days of production. Accounts receivable—other consist of amounts owed from interest owners of the Company’s operated wells. No interest is charged on past-due balances. Payments made on all accounts receivable are applied to the earliest unpaid items. The Company reviews accounts receivable periodically and reduces the carrying amount by a valuation allowance that reflects its best estimate of the amount that may not be collectible. There was no reserve for bad debts as of ~~June~~September 30, 2013 or December 31, 2012.

Other property

Furniture, fixtures and equipment are carried at cost. Depreciation of furniture, fixtures and equipment is provided using the straight-line method over estimated useful lives ranging from three to ten years. Gain or loss on retirement or sale or other disposition of assets is included in income in the period of disposition.

Income taxes

The Company is subject to U.S. federal income taxes along with state income taxes in Texas and New Mexico. When tax returns are filed, it is highly certain that some positions taken would be sustained upon examination by the taxing authorities, while others are subject to uncertainty about the merits of the position taken or the amount of the position that would be ultimately sustained. The benefit of a tax position is recognized in the financial statements in the period during which, based on all available evidence, management believes it is more likely than not that the position will be sustained upon examination, including the resolution of appeals or litigation processes, if any. Tax positions taken are not offset or aggregated with other positions. Tax positions that meet the more-likely-than-not recognition threshold are measured as the largest amount of tax benefit that is more than 50% likely of being realized upon settlement with the applicable taxing authority. The portion of the benefits associated with tax positions taken that exceeds the amount measured as described above is reflected as a liability for unrecognized tax benefits in the accompanying balance sheet along with any associated interest and penalties that would be payable to the taxing authorities upon examination. Interest and penalties associated with unrecognized tax benefits are classified as additional income taxes in the Company’s ~~Consolidated~~ Statements of Operations. The Company accrues interest and penalties, if any, related to unrecognized tax benefits as a component of income tax expense.

Deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to the differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using the tax rate in effect for the year in which those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the year of the enacted tax rate change. In addition, a valuation allowance is established to reduce any deferred tax asset for which it is determined that it is more likely than not that some portion of the deferred tax asset will not be realized.

Asset retirement obligations

Asset retirement obligations (“AROs”) associated with the retirement of tangible long-lived assets are recognized as liabilities with an increase to the carrying amounts of the related long-lived assets in the period incurred. The cost of the tangible asset, including the asset retirement cost, is depreciated over the useful life of the asset. AROs are recorded at estimated fair value, measured by reference to the expected future cash outflows required to satisfy the retirement obligations discounted at the Company’s credit-adjusted risk-free interest rate. Accretion expense is recognized over time as the discounted liabilities are accreted to their expected settlement value. If estimated future costs of AROs change, an adjustment is recorded to both the ARO and the long-lived asset. Revisions to estimated AROs can result from changes in retirement cost estimates, revisions to estimated inflation rates and changes in the estimated timing of abandonment.

Business combinations

We follow ASC 805, Business Combinations (“ASC 805”), and ASC 810-10-65, Consolidation (“ASC 810-10-65”). ASC 805 requires most identifiable assets, liabilities, non-controlling interests, and goodwill acquired in a business combination to be recorded at “fair value.” The statement applies to all business combinations, including combinations among mutual entities and combinations by contract alone. Under ASC 805, all business combinations will be accounted for by applying the acquisition method. Accordingly, transaction costs related to acquisitions are to be recorded as a reduction of earnings in the period they are incurred and costs related to issuing debt or equity securities that are related to the transaction will continue to be recognized in accordance with other applicable rules under U.S. GAAP. ASC 810-10-65 requires non-controlling interests to be treated as a separate component of equity, not as a liability or other item outside of permanent equity. The statement applies to the accounting for non-controlling interests and transactions with non-controlling interest holders in consolidated financial statements.

Earnings per common share

The Company reports basic earnings per common share, which excludes the effect of potentially dilutive securities, and diluted earnings per common share, which includes the effect of all potentially dilutive securities, unless their impact is anti-dilutive.

Recently issued accounting pronouncements

In May 2011, the FASB issued an accounting pronouncement related to fair value measurement (FASB ASC Topic 820), which amends current guidance to achieve common fair value measurement and disclosure requirements in U.S. GAAP and International Financial Reporting Standards. The amendments generally represent clarification of FAFASB ASC Topic 820, but also include instances where a particular principle or requirement for measuring fair value or disclosing information about fair value measurements has changed. This pronouncement is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011. We adopted this pronouncement for our fiscal year beginning January 1, 2012 and the adoption of this pronouncement did not have a material effect on our financial statements.

ASC Topic 820, but also include instances where a particular principle or requirement for measuring fair value or disclosing information about fair value measurements has changed. This pronouncement is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011. We adopted this pronouncement for our fiscal year beginning January 1, 2012 and the adoption of this pronouncement did not have a material effect on our consolidated financial statements.

In December 2011, the Financial Accounting Standards Board (“FASB”) issued new standards that require an entity to disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position. The new standards are effective for annual periods beginning on or after January 1, 2013. We are currently evaluating the provisions of the new standards and assessing the impact, if any, it may have on our financial position and results of operations.

4 – Asset retirement obligations

The following is a description of the changes to the Company’s asset retirement obligations for the periods ended ~~June~~September 30, 2013 and December 31, 2012:

	June 30,			December 31,
	September 30,			December 31,
	2013			2012
Asset retirement obligations at beginning of year	$	3,317,358		$	1,186,260
Disposal of assets		—			(88,650	)
Settlement of liabilities		—(1,284	)		(55,915	)
Revision of previous estimates		—			1,797,626
Accretion expense		71109,~~702~~684			94,556
Additions		1028,~~036~~024			383,481
Asset retirement obligations at end of period	$	3,~~399~~453,~~096~~782		$	3,317,358
Less: current portion		~~542~~455,~~443~~515			452,013
Long-term portion	$	2,~~856~~998,~~653~~267		$	2,865,345

5 – Property and equipment

Oil and natural gas properties

The following table sets forth the capitalized costs under the successful efforts method for oil and natural gas properties:

	June 30,			December 31,
	September 30,				December 31,
	2013			~~2012~~	2012
Oil and natural gas properties	$	5455,~~125~~245,~~148~~214		$	~~34,986,566~~$	48,248,378
Less accumulated depletion and impairment		(1819,~~804~~881,~~212~~867	)		~~(9,667,031~~	)(16,018,892	)
Net oil and natural gas properties capitalized costs	$	35,~~320~~363,~~936~~347		$	~~25,319,535~~$	32,229,486

Capitalized costs related to proved oil and natural gas properties, including wells and related equipment and facilities, are evaluated for impairment based on the Company’s analysis of undiscounted future net cash flows. If undiscounted future net cash flows are insufficient to recover the net capitalized costs related to proved properties, then the Company recognizes an impairment charge in income equal to the difference between carrying value and the estimated fair value of the properties. Estimated fair values are determined using discounted cash flow models. The discounted cash flow models include management’s estimates of future oil and natural gas production, operating and development costs, and discount rates.

Uncertainties affect the recoverability of these costs as the recovery of the costs outlined above are dependent upon the Company obtaining and maintaining leases and achieving commercial production or sale.

Other property and equipment

The historical cost of other property and equipment, presented on a gross basis with accumulated depreciation is summarized as follows:

	June 30,			December 31,
	September 30,				December 31,
	2013			~~2012~~	2012
Other property and equipment	$	130,~~469~~470		$	~~130,470~~$	130,470
Less accumulated depreciation		(8691,~~509~~169	)		~~(77,190~~	)(77,190	)
Net property and equipment	$	4339,~~960~~301		$	~~53,280~~$	53,280

6 – Stockholders’ equity and earnings per share

2011 Equity Financing

On May 26, 2011, the Company closed a private offering exempt from registration under the Securities Act of 1933 pursuant to Rule 506 of Regulation D promulgated thereunder. In the offering, the Company issued an aggregate of 3,600,000 units. Each unit was sold at $1.50 and was comprised of one share of common stock and one five-year warrant to purchase a share of common stock at an exercise price of $2.25 per share. The warrants became exercisable on November 26, 2011. The Company agreed to use the net proceeds from the sale of the units for general business and working capital purposes and not to use such proceeds for the redemption of any common stock or common stock equivalents.

The investors in the offering (“Selling Stockholders”) received registration rights. The Company agreed to file a registration statement covering the resale of the common stock issued and the common stock underlying the warrants issued to the Selling Stockholders within sixty days after the closing date. If the registration statement was not declared effective by the SEC within the time periods defined within the agreement, then the Company would have made pro rata cash payments to each Selling Stockholder as liquidated damages in an amount equal to 1.0% of the aggregate amount invested by such Selling Stockholder for each 30-day period or pro rata for any portion thereof following the date by which such Registration Statement should have been effective. If at the time of exercise of the warrants there is no effective registration statement covering the resale of the shares underlying the warrant, then the Selling Stockholders have the right at such time to exercise warrants in full or in part on a cashless basis. The Company filed an S-1 registration statement registering the shares on July 25, 2011, which was declared effective on August 5, 2011.

In addition to registration rights, the Selling Stockholders were offered a right of first refusal to participate in future offerings of common stock if the principal purpose of which was to raise capital. This right of first refusal terminated upon the one-year anniversary of the closing date.

Warrants

In connection with the equity offering closed on May 26, 2011, the Company issued warrants to purchase an aggregate of 3,600,000 shares of the Company’s common stock at a per share price of $2.25 (the "$2.25 Warrants"). The Company also has outstanding warrants to purchase 3,125 shares of the Company’s common stock at a per share price of $5.00. The $2.25 Warrants became exercisable in November 2011 and expire in November 2015. On the date of issuance, the warrants were valued at $898,384. Management determined the fair value of the warrants based upon the Black-Scholes option model with a volatility based on the historical closing price of common stock of industry peers and the closing price of the Company’s common stock on the OTCBB on the date of issuance. The volatility and remaining term was 50% and 2.92 years, respectively. The Company does not expect the immediate exercise of these warrants as the exercise price exceeds the average closing market price for the Company's common stock. Furthermore, no assurances can be made that any of the warrants will ever be exercised for cash or at all.

Issuance of Shares to Former Executive

On November 7, 2012, the Company issued 150,000 shares (the “Shares”) of its common stock to Everett Willard Gray II, in full satisfaction of any remaining amounts owed to Mr. Gray by the Company pursuant to Mr. Gray’s employment agreement with the Company, dated as of January 31, 2011 and amended as of March 6, 2012 and April 20, 2012 (as amended, the “Employment Agreement”). Mr. Gray resigned as the Company’s Chairman and Chief Executive Officer effective May 31, 2012 in connection with the transactions described in the Company’s Current Report on Form 8-K filed on April 24, 2012. The Employment Agreement provided for him to receive severance payments of $478,298, payable in installments, of which $239,149 remained to be paid, which was satisfied by the issuance of the 150,000 shares.

Stock Options

In 2011, the Company issued options to purchase 8587,~~000~~500 shares of its common stock at $4.80 to its directors. For the year ended December 31, 2012 and the ~~six~~nine months ended ~~June~~September 30, 2013, there was no stock based compensation.

Stock option activity summary is presented in the table below:

							~~Weighted-~~	Weighted-
							~~average~~	average
				~~Weighted-~~	Weighted-		~~Remaining~~	Remaining
				~~average~~	average		~~Contractual~~	Contractual
	Number of			~~Exercise~~	Exercise		~~Term~~	Term
	Shares			~~Price~~	Price		~~(years)~~	(years)
Outstanding at December 31, 2011	~~87,500~~	87,500	$	~~4.80~~	$	4.80	~~5.08~~		4.08
Granted	—	—		—		—	—		—
Cancelled	—	—		—		—	—		—
Exercised	—	—		—		—	—		—
Forfeited	—	—		—		—	—		—
Expired	—	—		—		—	—		—
Outstanding and exercisable at December 31, 2012	~~87,500~~	87,500		~~4.80~~		4.80	~~4.08~~		3.08
Granted	—	—		—		—	—		—
Cancelled	—	—		—		—	—		—
Exercised	—	—		—		—	—		—
Forfeited	—	—		—		—	—		—
Expired	—	—		—		—	—		—
Outstanding and exercisable at June 30, 2013	87,500		$	4.80			3.83
Outstanding and exercisable at September 30, 2013		87,500			$	4.80			3.83

There is no intrinsic value in the outstanding options since the option price is in excess of the market price of the Company's common stock.

The fair value of the options granted during 2011 was estimated at the date of grant using the Black-Scholes option-pricing model with the following assumptions:

Closing market price of stock on grant date	$3.11
Risk-free interest rate	2.43%
Dividend yield	0.00%
Volatility factor	50%
Expected life	2.5 years

We The Company elected to use the “simplified” method to calculate the estimated life of options granted to employees. The use of the “simplified” method has been extended until such time when wethe ~~have~~Company has sufficient information to make more refined estimates on the estimated life of ~~our~~its options. The expected stock price volatility was calculated by averaging the historical volatility of the Company’s common stock over a term equal to the expected life of the options.

Issuance of Common Shares to Settle Creditors Payable

As described in Note 9, the Company entered into settlement agreements with two of the creditors payable arising out of the 2002 bankruptcy. The Company paid the creditors $633,975 in cash and the Company’s largest shareholder, Red Mountain Resources, Inc. (“RMR”), issued approximately 750,000 shares of its common stock to the creditors in settlement of the claims. In return for ~~Red~~RMR ~~Mountain Resources, Inc.~~ issuing its shares to the creditors payable, the Company issued ~~Red~~RMR ~~Mountain~~ 422,650 shares of its common stock.

Conversion of Notes Payable

On February 28, 2013, ~~Red Mountain Resources~~RMR, ~~Inc.,~~ the holder of the Green Shoe and Little Bay notes, elected to convert the outstanding notes and accrued interest into common shares. The board of directors of the Company had previously resolved to change the conversion feature from $4.00 per common share to $1.50 per common share. As a result, the Company issued 611,630 common shares to ~~Red Mountain Resources, Inc~~RMR.

7 – Related party transactions

On April 11, 2012, the Company advanced its then Chief Executive Officer, E. Willard Gray, II, $119,575 related to the change in control provisions in Mr. Gray's employment agreement. At ~~June~~September 30, 2012, $42,070 remained outstanding (shown as Accounts receivable - related party on the Balance Sheet), which was deducted from the second change of control payment to him from the Company in July 2012.

During the year ended December 31, 2012, ~~Red~~RMR ~~Mountain Resources, Inc.~~ incurred approximately $628,274 for general and administrative expenses and operating costs that will be reimbursed by the Company for accounting services and attendance of certain of the Company’s directors and officers at the Company’s annual meeting of stockholders and for costs associated with workovers on three of the Company’s salt water disposal wells, of which $215,495 remained unpaid at December 31, 2012. The expenditures pertaining to the operating costs were incurred pursuant to a technical services agreement between the Company and ~~Red Mountain Resources, Inc~~RMR. During the ~~six~~nine months ended ~~June~~September 30, 2013, ~~Red~~RMR ~~Mountain~~ incurred approximately $~~490~~1,~~508~~830,006 of such expenditures (including a $900,000 cash advance), $~~409~~1,~~391~~830,006 of which remained unpaid at ~~June~~September 30, 2013.

8 – Long term debt

Notes Payable Green Shoe Investments – Related Party

In connection with the January 2011 merger, the Company, as the accounting acquirer, assumed an unsecured loan from Green Shoe Investments Ltd. (“Green Shoe”) in the principal amount of $487,000 at an interest rate of 5.0%

On April 26, 2011, the Company entered into a Loan Agreement with Green Shoe, and the Company executed and delivered a Promissory Note to Green Shoe in connection therewith. The amount of the Promissory Note and the loan from Green Shoe (the “Green Shoe Loan”) was $550,936 and the purpose of the Green Shoe Loan was to consolidate and extend all of the loans owed by the Company and its predecessors to Green Shoe including without limitation the following: (i) loan dated May 9, 2008 in the principal amount of $100,000, (ii) loan dated May 23, 2008 in the principal amount of $150,000, (iii) loan dated July 18, 2008 in the principal amount of $50,000, (iv) loan dated February 24, 2009 in the principal amount of $100,000, and (v) loan dated April 29, 2009 in the principal amount of $87,000 plus accrued interest of $63,936. The Green Shoe Loan was unsecured.

Beginning March 31, 2011 (the effective date of the Promissory Note), the amounts owed under the Promissory Note began to accrue interest at a rate of 9.99%, and the Promissory Note provided that no payments of principal or interest were due until the maturity date of September 30, 2012. The Company is obligated to pay all accrued interest and make a principal payment equal to one-third of the principal owed upon the closing of an equity offering resulting in a specified amount of net proceeds to the Company. In addition, Green Shoe was granted the right to convert the principal and interest owed into shares of common stock of the Company at a conversion price of $4.00 per share. The principal balance of the note as of September 30, 2012 was $367,309.

The debt and associated accrued interest were not repaid at maturity on September 30, 2012. On October 22, 2012, the Company received notice from the lender’s counsel that it would be considered in default on the note beginning November 1, 2012 if the note and accrued interest were not paid in full. From November 1, 2012, the note began to accrue interest at the default rate of 18%. On November 30, 2012, Jackson Street Investors, LLC purchased the note from Green Shoe Investments. Subsequently, on December 12, 2012, ~~Red~~RMR ~~Mountain Resources, Inc.~~ purchased the note from Jackson Street Investors, LLC. As of December 31, 2012, the note had a principal balance of $367,309 and an accrued interest balance of $62,924.

On February 28, 2013, the Company’s Board of Directors approved a resolution to modify the terms of the note so that the conversion price was reduced from $4.00 to $1.50 per share. On February 28, 2013, ~~Red~~RMR ~~Mountain Resources, Inc.~~ converted the principal balance of $367,309 and accrued interest balance of $73,611 into 293,947 shares of the Company’s common stock.

Notes Payable Little Bay Consulting – Related Party

In connection with the January 2011 merger, the Company, as the accounting acquirer, assumed an unsecured loan from Little Bay Consulting SA (“Little Bay”) in the principal amount of $520,000 at an interest rate of 5%.

On April 26, 2011, the Company entered into a Loan Agreement with Little Bay, and the Company executed and delivered a Promissory Note to Little Bay in connection therewith. The amount of the Promissory Note and the loan from Little Bay (the “Little Bay Loan”) was $595,423 and the purpose of the Little Bay Loan was to consolidate and extend all of the loans owed by the Company and its predecessors to Little Bay including without limitation the following: (i) loan dated March 7, 2008 in the original principal amount of $220,000, (ii) loan dated July 18, 2008 in the original principal amount of $100,000, and (iii) loan dated October 3, 2008 in the principal amount of $200,000 plus accrued interest of $75,423. The Little Bay Loan was unsecured.

Beginning March 31, 2011 (the effective date of the Promissory Note), the amounts owed under the Promissory Note began to accrue interest at a rate of 9.99%, and the Promissory Note provided that no payments of principal or interest were due until the maturity date of September 30, 2012. The Company is obligated to pay all accrued interest and make a principal payment equal to one-third of the principal owed upon the closing of an equity offering resulting in a specified amount of net proceeds to the Company. In addition, Little Bay was granted the right to convert the principal and interest owed into shares of common stock of the Company at a conversion price of $4.00 per share. The principal balance of the note as of September 30, 2012 is $396,969.

The debt and associated accrued interest were not repaid at maturity on September 30, 2012. On October 22, 2012, the Company received notice from the lender’s counsel that it would be considered in default on the note beginning November 1, 2012 if the note and accrued interest were not paid in full. From November 1, 2012, the note began to accrue interest at the default rate of 18%. On November 30, 2012, Jackson Street Investors, LLC purchased the note from Little Bay Consulting, S.A. Subsequently, on December 12, 2012, ~~Red~~RMR ~~Mountain Resources, Inc.~~ purchased the note from Jackson Street Investors, LLC. As of December 31, 2012, the note had a principal balance of $396,969 and an accrued interest balance of $68,005.

On February 28, 2013, the Company’s Board of Directors approved a resolution to modify the terms of the note so that the conversion price was reduced from $4.00 to $1.50 per share. On February 28, 2013, ~~Red~~RMR ~~Mountain Resources, Inc.~~ converted the principal balance of $396,969 and accrued interest balance of $79,555 into 317,683 shares of the Company’s common stock.

Operating Line of Credit

As of December 31, 2011, the borrowing base on the Texas Capital Bank (“TCB”) line of credit was $4,500,000. Effective March 1, 2012, the borrowing base was increased to $9,500,000. The interest rate was calculated at the greater of the adjusted base rate or 4%. The line of credit is collateralized by producing wells and was set to mature on January 14, 2014. As a result of the sale of certain interests in oil and gas properties, effective August 1, 2012, the borrowing base was reduced by $750,000 and that amount was repaid to TCB out of the sale proceeds.

On February 5, 2013, the Company entered into a Senior First Lien Secured Credit Agreement with ~~Red Mountain Resources~~RMR, ~~Inc.,~~ Black Rock Capital, Inc. and RMR Operating, LLC and Independent Bank, as Lender. ~~Red~~RMR ~~Mountain~~ owns approximately 81% of the outstanding common stock of Cross Border and Black Rock and RMR Operating are wholly owned subsidiaries of ~~Red Mountain~~RMR. On February 5, 2013, the Company drew $8,900,000 on the line of credit and used those funds to pay off the line of credit and associated accrued interest. On February 29, 2013, the Company drew $2,000,000 and on May 24, 2013, the Company drew a further $1,300,000 on the line of credit and used those funds to pay accounts payable related to the drilling program. As of ~~June~~September 30, 2013, the Credit Agreement balance was $12,200,000, leaving $~~200~~7,800,000 available.

The borrowing base under the Credit Facility is determined at the discretion of the Lender based on, among other things, the Lender’s estimated value of the proved reserves attributable to the Borrowers’ oil and natural gas properties that have been mortgaged to the Lender, and is subject to regular redeterminations on September 30 and March 31 of each year, and interim redeterminations described in the Credit Agreement and potentially monthly commitment reductions, in each case which may reduce the amount of the borrowing base. As of September 30, 2013, the borrowing base was $30,000,000 million, leaving $17,800,000 of availability.

9 – Creditors payable

In 2002, the prior owner of Pure Sub filed a petition for reorganization with the United States Bankruptcy Court. According to the plan of reorganization, three creditors were to receive a combined amount of approximately $3,000,000 for their claims out of future net revenues of Pure Sub (defined as revenues from producing wells net of lease operating expenses and other direct costs).

On February 28, 2013, the Company entered into settlement agreements with two of the creditors. Under the agreement, one creditor with a balance of $608,727 as of December 31, 2012 was paid $304,363 in cash and the Company arranged for its largest shareholder, ~~Red Mountain Resources~~RMR, to issue the creditor 358,075 shares of ~~Red Mountain~~RMR’s common stock. The other creditor with a balance of $659,224 as of December 31, 2012 was paid $329,612 and the Company arranged for ~~Red~~RMR ~~Mountain~~ to issue the creditor 387,779 shares of ~~Red Mountain~~RMR’s common stock.

10 – Commitments and contingencies

Litigation

On May 4, 2011, Clifton M. (Marty) Bloodworth filed a lawsuit in the State District Court of Midland County, Texas, against Doral West Corp. d/b/a Doral Energy Corp. and Everett Willard Gray II. Mr. Bloodworth alleges that Mr. Gray, as CEO of the Company, made false representations which induced Mr. Bloodworth to enter into an employment contract that was subsequently breached by the Company. The claims that Mr. Bloodworth has alleged are: breach of his employment agreement with Doral, common law fraud, civil conspiracy breach of fiduciary duty, and violation of the Texas Deceptive Trade Practices-Consumer Protection Act. Mr. Bloodworth is seeking damages of approximately $280,000. Mr. Gray and the Company deny that Mr. Bloodworth’s claims have any merit.

The Company was previously party to an engagement letter, dated February 7, 2012 (the "Engagement Letter"), with KeyBanc Capital Markets Inc. ("KeyBanc") pursuant to which KeyBanc was to act as exclusive financial advisor to the Company’s Board of Directors in connection with a possible "Transaction" (as defined in the Engagement Letter). The Engagement Letter was formally terminated by the Company on August 21, 2012. The Engagement Letter provided that KeyBanc would be entitled to a fee upon consummation of a Transaction within a certain period of time following termination of the Engagement Letter. On May 16, 2013, KeyBanc delivered an invoice to the Company in the amount of $751,334, representing amounts purportedly owed by the Company to KeyBanc as a result of the consummation of a purported Transaction KeyBanc asserts had been consummated within the required time period and its out-of-pocket expenses in connection therewith. The Company disputes that any Transaction was consummated and that KeyBanc is entitled to any out-of-pocket expenses. The matter was originally filed in the 44th-B Judicial District Court for the State of Texas, Dallas County but was subsequently removed to the United States District Court for the Northern District of Texas, Dallas Division. The Company intends to vigorously defend the action.

Environmental Contingencies

The Company is subject to federal and state laws and regulations relating to the protection of the environment. Environmental risk is inherent to oil and natural gas operations and the Company could be subject to environmental cleanup and enforcement actions. The Company manages this environmental risk through appropriate environmental policies and practices to minimize the impact to the Company.

As of ~~June~~September 30, 2013, the Company had approximately $2,100,000 in environmental liabilities related to its operated Tom Tom Tomahawk field located in Chaves and Roosevelt counties New Mexico. In February 2013, the Bureau of Land Management (“BLM”) accepted the Company’s remediation plan for the Tom Tom and Tomahawk fields. The Company is working in conjunction with the BLM to initiate remediation on a site-by-site basis. This is management’s best estimate of the costs of remediation and restoration with respect to these environmental matters, although the ultimate cost could differ materially. Inherent uncertainties exist in these estimates due to unknown conditions, changing governmental regulation, and legal standards regarding liability, and emerging remediation technologies for handling site remediation and restoration. The Company expects to incur these expenditures over a twenty-four month period beginning in ~~April~~September 2013.

11 – Price risk management activities

ASC 815-25 (formerly SFAS No. 133 “Accounting for Derivative Instruments and Hedging Activities”) requires that all derivative instruments be recorded on the balance sheet at their fair value. Changes in the fair value of each derivative are recorded each period in current earnings or other comprehensive income, depending on whether the derivative is designated as part of a hedge transaction and, if it is, the type of hedge transaction. When choosing to designate a derivative as a hedge, management formally documents the hedging relationship and its risk-management objective and strategy for undertaking the hedge, the hedging instrument, the item, the nature of the risk being hedged, how the hedging instrument’s effectiveness in offsetting the hedged risk will be assessed, and a description of the method of measuring effectiveness. This process includes linking all derivatives that are designated as cash-flow hedges to specific cash flows associated with assets and liabilities on the balance sheet or to specific forecasted transactions. Based on the above, management has determined the swaps noted below do not qualify for hedge accounting treatment.

At ~~June~~September 30, 2013, the Company had a net derivative ~~asset~~liability of $~~155~~92,~~744~~392, as compared to a net derivative asset of $290,788 at December 31, 2012. The change in net derivative asset/liability is recorded as non-cash mark-to-market income or loss. Mark-to-market losses of $89338,~~978~~114 were recorded in the ~~six~~nine months ended ~~June~~September 30, 2013 as compared to mark-to-market income of $245,722 during the twelve months ended December 31, 2012. Net realized hedge settlement gain for the ~~six~~nine months ended ~~June~~September 30, 2013 was $6710,~~421~~699 as compared to net realized hedge settlement gain of $317,593 for the twelve months ended December 31, 2012. The combination of these two components of derivative expense/income is reflected in "Other Income (Expense)" on the Statements of Operations as "Gain (loss) on derivatives."

As of ~~June~~September 30, 2013, the Company had crude oil swaps in place relating to a total of 3,000 Bbls per month, as follows:

				Price	Volumes	Fair Value of Outstanding Derivative Contracts (1) as of
Transaction				Per	Per		~~June~~September 30,		December
Date	Type (2)	Beginning	Ending	Unit	Month		2013		31, 2012
March 2011	Swap	04/01/2011	02/28/2013	$104.55	1,000	$	—	$	41,019
November 2011	Swap	12/01/2011	11/30/2014	$93.50	2,000		—		44,942
February 2012	Swap	03/01/2012	02/28/2014	$106.50	1,000		—		204,827
February 2013	Swap	03/01/2013	11/01/2014	$93.50	2,000		48(29,~~570~~486)		—
February 2013	Swap	03/01/2013	02/01/2014	$106.50	1,000		~~107~~121,~~174~~878		—
						$	~~155~~92,~~744~~392	$	290,788

(1) The fair value of the Company's outstanding transactions is presented on the balance sheet by counterparty. Currently all of our derivatives are with the same counterparty. The balance is shown as current or long-term based on our estimate of the amounts that will be due in the relevant time periods at currently predicted price levels. Amounts in parentheses indicate liabilities.

(2) These crude oil hedges were entered into on a per barrel delivered price basis, using the NYMEX - West Texas Intermediate Index, with settlement for each calendar month occurring following the expiration date, as determined by the contracts.

12 – Fair Value Measurements

Fair value measurements are based upon inputs that market participants use in pricing an asset or liability, which are classified into two categories: observable inputs and unobservable inputs. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect a company’s own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. These two types of inputs are further prioritized into the following fair value input hierarchy:

Level 1 –

quoted prices for identical assets or liabilities in active markets.

Level 2 –

quoted prices for similar assets or liabilities in active markets; quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability (e.g. interest rates) and inputs derived principally from or corroborated by observable market data by correlation or other means.

Level 3 –

unobservable inputs for the asset or liability.

The fair value input hierarchy level to which an asset or liability measurement in its entirety falls is determined based on the lowest level input that is significant to the measurement in its entirety.

~~The following tables summarize the valuation of the Company’s financial assets and liabilities at June 30, 2013 and December 31, 2012:~~16

	Fair Value Measurements at Reporting Date Using
	Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1)		Significant or Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)			Fair Value at June 30, 2013
Assets:
Commodities derivatives	$	—	$	155,744	$	—		$	155,744
Total	$	—	$	155,744	$	—		$	155,744
Liabilities
Environmental liability	$	—	$	—	$	(2,088,158	)	$	(2,088,158	)
Asset retirement obligations (non-recurring)	$	—	$	—	$	(3,399,096	)	$	(3,399,096	)
Total	$	—	$	—	$	(5,487,254	)	$	(5,487,254	)

The following tables summarize the valuation of the Company’s financial assets and liabilities at September 30, 2013 and December 31, 2012:

	Fair Value Measurements at Reporting Date Using
	Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1)		Significant or Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)			Fair Value at September 30, 2013
Assets:
Commodities derivatives	$	—	$	3,504		$	—		$	3,504
Total	$	—	$	3,504		$	—		$	3,504
Liabilities
Environmental liability	$	—	$	—		$	(2,086,833	)	$	(2,086,833	)
Asset retirement obligations (non-recurring)	$	—	$	—		$	(3,453,782	)	$	(3,453,782	)
Commodities Derivative	$	—	$	(95,896	)	$	—		$	$(95,896	)
Total	$	—	$	(95,896	)	$	(5,540,615	)	$	(5,636,511	)

	Fair Value Measurements at Reporting Date Using
(in thousands)	Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1)		Significant or Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)			Fair Value at December 31, 2012
Assets:
Commodities derivatives	$	—	$	290,788	$	—		$	290,788
Total	$	—	$	290,788	$	—		$	290,788

Liabilities:
Environmental liability	$	—	$	—	$	(2,100,000	)	$	(2,100,000	)
Asset retirement obligations (non-recurring)		—		—		(3,317,358	)		(3,317,358	)
Total	$	—	$	—	$	(5,417,358	)	$	(5,417,358	)

The following is a summary of changes to fair value measurements using Level 3 inputs during the three months ended ~~June~~September 30, 2013:

	Environmental Liability
Balance, December 31, 2012	$	2,100,000
Acquisitions		—
Settlement of liabilities		1113,~~842~~167
Revisions of previous estimates		—
Balance, June 30, 2013	$	2,088,158
Balance, September 30, 2013	$	2,086,833

1817

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Our Company

We are an oil and gas exploration and development company. We currently own over 865,893 gross (approximately 293,843 net) mineral and lease acres in New Mexico ~~and Texas~~. Approximately 25,000 of these net acres exist within the Permian Basin. A significant majority of our acreage consists of either owned mineral rights or leases held by production. The majority of our acreage interests consists of non-operated working interests except for certain core San Andres properties which we operate.

Current development of our acreage is focused on our prospective Bone Spring acreage located in the heart of the 1st and 2nd Bone Spring play. This play encompasses approximately 4,390 square miles across both New Mexico and Texas. We currently own varying, non-operated working interests in both Eddy and Lea Counties, New Mexico, along with our working interest partners that include Cimarex, Apache, Oxy Permian, Occidental, Oxy USA and, Mewbourne; all having significant footprints within this play, and are adding to those footprints through lease and corporate acquisitions.

History

We were originally formed on October 25, 2005 under the name “Language Enterprises Corp.” We subsequently changed our name to Doral Energy Corp. On July 29, 2008, we acquired a working interest in 66 producing oil fields and approximately 186 wells (the “Eddy County Properties”) in and around Eddy County, New Mexico. As a result of our acquisition of the Eddy County Properties, we changed our business focus to the acquisition, exploration, operation and development of oil and gas projects, and we ceased being a “shell company.” On August 4, 2008, we filed our Form 8-K that included the information that would be required if we were filing a general form for registration of securities on Form 10 as a smaller reporting company.

Effective January 3, 2011, we completed the acquisition of Pure Energy Group, Inc. as contemplated pursuant to the Pure Merger Agreement among our company, Doral Sub, Pure L.P. and Pure Sub, a wholly owned subsidiary of Pure L.P. Pursuant to the provisions of the Pure Merger Agreement, all of Pure L.P.’s oil and gas assets and liabilities were transferred to Pure Sub. Pure Sub was then merged with and into Doral Sub, with Doral Sub continuing as the surviving corporation. Upon completion of the Pure Merger, the outstanding shares of Pure Sub were converted into an aggregate of 9,981,536 shares of our common stock. Since the Pure Merger, Pure L.P. has distributed all of its shares of our common stock to the partners of Pure L.P. so that Pure L.P. is no longer a shareholder of our company.

Effective January 4, 2011, following closing of the Pure Merger, Doral Sub was merged with and into our company, with our company continuing as the surviving corporation. Upon completing the merger of Doral Sub with and into our company, we changed our name to “Cross Border Resources, Inc.”

On January 28, 2013, Red Mountain Resources, Inc. closed the acquisition of 5,091,210 shares of our common, bringing its total ownership to approximately 78% of the outstanding common stock of the company. Prior to the acquisition, Red Mountain Resources, Inc. owned 47% of our outstanding common stock. As of the date of this report, Red Mountain Resources, Inc. owns approximately 8183% of our outstanding common stock. As a result of that transaction, our results are consolidated in Red Mountain Resources, Inc.’s financial statements.

~~First~~Third Quarter 2013 Operational Update

In the ~~first~~nine ~~half~~months ofended ~~fiscal~~ 9/30/2013, weCross Border completed 1518 gross wells (1.4052 net). These included 6 horizontal Bone Spring wells (0.91 net), 23 horizontal Glorieta-Yeso wells (0.1117 net), 68 vertical Glorieta-Yeso wells (0.3238 net), and 1 vertical Queen-Grayburg-San ~~Andres~~Andrew well (0.06 net). ~~On June 30, 2013, there were 2 wells (0.06 net) drilled and awaiting completions. Both are vertical Glorieta-Yeso wells.~~ Also during ~~this~~the period, we received approval to begin remediation work and field redevelopment in the Tom Tom area. The first work was performed in May. At the end of the third quarter, 3several workovers ~~were~~had been completed, ~~each~~including ~~showing~~2 ~~positive~~recompletions ~~results~~that added new zones to production.

Planned Operations

WeIn the remainder of 2013, we plan to spend between $~~8 million~~ 2 and $123 million ~~during fiscal 2013~~ to drill and complete wells, re-enter and complete wells, or improve infrastructure. Our main area of focus is the Tom Tom~~/Tomahawk~~ ~~Prospect~~area, where wework will ~~work~~continue onto remediate the field ~~alongside~~and ~~the~~improve ~~execution~~production offrom ~~our~~existing ~~remediation plan~~wells. ~~For~~In ~~fiscal~~the ~~2013,~~fourth quarter this includes the re-entry of 142 ~~gross~~additional wells ~~(11.7 net), drilling of 6 gross wells (5.2 net),~~ and ~~the~~ improvement ofto the field infrastructure. WeIn ~~will~~our ~~also spend capital in several~~ non-operated prospect areas~~. Currently~~, we are committed to participating in the drilling of 34 gross ~~wells~~ (0.352 net), and we expect to receive ~~addition~~some additional well proposals before the end of fiscal 2013. We expect to finance these activities with ~~cashflow~~cash flow generated from operations and availability under our line of credit with Independent Bank.

1918

Critical Accounting Policies and Estimates

Our discussion and analysis of our financial condition and results of operations is based upon our ~~consolidated~~ financial statements, which have been prepared in accordance with U.S. generally accepted accounting principles (“GAAP”). The preparation of these ~~consolidated~~ financial statements requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenue and expenses, and related disclosures. Our significant accounting policies are described in “Note 3—Summary of Significant Accounting Policies” to our ~~consolidated~~ financial statements included in this Annual Report on Form 10-K. We have identified below policies that are of particular importance to the portrayal of our financial position and results of operations and which require the application of significant judgment by management. These estimates are based on historical experience, information received from third parties, and on various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates under different assumptions or conditions.

We believe the following critical accounting policies affect the significant judgments and estimates used in the preparation of our ~~consolidated~~ financial statements.

Oil and Gas Properties

We follow the successful efforts method of accounting for our oil and natural gas producing activities. Costs to acquire mineral interests in oil and natural gas properties and to drill and equip development wells and related asset retirement costs are capitalized. Costs to drill exploratory wells are capitalized pending determination of whether the wells have proved reserves. If we determine that the wells do not have proved reserves, the costs are charged to expense. There were no exploratory wells capitalized pending determination of whether the wells have proved reserves at ~~December~~September 3130, ~~2012~~2013 or ~~2011~~December 31, 2012. Geological and geophysical costs, including seismic studies and costs of carrying and retaining unproved properties, are charged to expense as incurred. We capitalize interest on expenditures for significant exploration and development projects that last more than six months while activities are in progress to bring the assets to their intended use. Through December 31, 2012, we had capitalized no interest costs because our exploration and development projects generally lasted less than six months. Costs incurred to maintain wells and related equipment are charged to expense as incurred.

Capitalized amounts attributable to proved oil and natural gas properties are depleted by the unit-of-production method over proved reserves using the unit conversion ratio of six Mcf of natural gas to one Boe. The ratio of six Mcf of natural gas to one Boe is based on energy equivalency, rather than price equivalency. Given current price differentials, the price for a Boe for natural gas differs significantly from the price for a barrel of oil.

It is common for operators of oil and natural gas properties to request that joint interest owners pay for large expenditures, typically for drilling new wells, in advance of the work commencing. This right to call for cash advances is typically found in the operating agreement that joint interest owners in a property adopt. We record these advance payments in prepaid and other current assets in its property account and release this account when the actual expenditure is later billed to it by the operator.

Impairment of Long-Lived Assets

We evaluate our long-lived assets for potential impairment in their carrying values whenever events or changes in circumstances indicate such impairment may have occurred. Oil and natural gas properties are evaluated for potential impairment by field. Other properties are evaluated for impairment on a specific asset basis or in groups of similar assets, as applicable. An impairment on proved properties is recognized when the estimated undiscounted future net cash flows of an asset are less than its carrying value. If an impairment occurs, the carrying value of the impaired asset is reduced to its estimated fair value, which is generally estimated using a discounted cash flow approach. If the results of an assessment indicate that the properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized.

Unproved oil and natural gas properties do not have producing properties. As reserves are proved through the successful completion of exploratory wells, the cost is transferred to proved properties. The cost of the remaining unproved basis is periodically evaluated by management to assess whether the value of a property has diminished. To do this assessment, management considers estimated potential reserves and future net revenues from an independent expert, our history in exploring the area, our future drilling plans per our capital drilling program prepared by our reservoir engineers and operations management and other factors associated with the area. Impairment is taken on the unproved property cost if it is determined that the costs are not likely to be recoverable. The valuation is subjective and requires management to make estimates and assumptions which, with the passage of time, may prove to be materially different from actual results.

In the second quarter of 2012, the Company determined to sale its Wolfberry assets located in Texas. As a result of that decision, management conducted an impairment evaluation of those assets which resulted in a non cash impairment charge of approximately $1,776,000.

Additionally, during the fourth quarter of 2012, management conducted an impairment evaluation of its proved and unproved oil and natural gas properties. As a result of the evaluation, management recorded a non cash impairment charge of approximately $1,208,000, primarily related to a decline in the value of proved reserves.

Recent Accounting Pronouncements

In May 2011, the FASB issued an accounting pronouncement related to fair value measurement (FASB ASC Topic 820), which amends current guidance to achieve common fair value measurement and disclosure requirements in U.S. GAAP and International Financial Reporting Standards. The amendments generally represent clarification of FASB ASC Topic 820, but also include instances where a particular principle or requirement for measuring fair value or disclosing information about fair value measurements has changed. This pronouncement is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011. We adopted this pronouncement for our fiscal year beginning January 1, 2012 and the adoption of this pronouncement did not have a material effect on our consolidated financial statements.

In January 2010, the FASB issued new standards intended to improve disclosures about fair value measurements. The new standards require details of transfers in and out of Level 1 and Level 2 fair value measurements and the gross presentation of activity within the Level 3 fair value measurement roll forward. The new disclosures are required of all entities that are required to provide disclosures about recurring and nonrecurring fair value measurements. We adopted these new rules effective January 1, 2010.

Results of Operations

Three Months Ended ~~June~~September 30, 2013 Compared to Three Months Ended ~~June~~September 30, 2012

The following table sets forth summary information regarding our oil and natural gas sales, net production sold, average sales prices and production costs and expenses for the three months ended ~~June~~September 30, 2013 and 2012.

	Three Months Ended June 30,
	Three Months Ended September 30,
	2013		2012
(dollars in thousands, except per unit prices)
Revenue
Oil and natural gas sales	$	3,461,249	$	4,147,645
Total Sales	$	3,430,100	$	2,811,224
Salt Water Disposal Sales		16,470		0
Oil and Natural Gas Sales		3,413,145		2,811,224
Net Production sold
Oil (Bbl)		3531,~~601~~329		4230,~~105~~634
Natural gas (Mcf)		5685,~~550~~428		59,~~121~~342
Total (Boe)		45,~~026~~567		5140,~~959~~524
Total (Boe/d) (1)		495		~~571~~440
Average sales prices
Oil ($/Bbl)	$	8996.8505	$	8882.8719
Natural gas ($/Mcf)		53.4275		42.7888
Total average price ($/Boe)	$	7774.9790	$	74.65
Costs and expenses (per Boe)
Operating costs	$	19.80	$	11.67
Operating costs and marketing	$	12.05	$	10.79
Production taxes		58.6553		75.0939
Depreciation, depletion, and amortization		3723.2975		5333.2706
Accretion of discount on asset retirement obligation		0.8283		0.5644
General and administrative expense		5.8552		3012.0636

_________________

(1) Boe/d is calculated based on actual calendar days during the period.

Three months Revenues and Sales Volumes

Oil and Natural Gas Sales Volumes. During the three months ended ~~June~~September 30, 2013, we had total sales volumes of 45,~~026~~567 Boe, compared to total sales volumes of 5140,~~959~~524 Boe during the three months ended ~~June~~September 30, 2012. This ~~decline~~increase is ~~partially~~primarily attributable to ~~our former Wolfberry assets, which were sold effective August 1, 2012, which contributed approximately 3,200 Boe to sales volumes during~~ the ~~three~~bringing ~~months~~online ~~ended~~of ~~June~~new ~~30,~~oil ~~2012. Also~~and ~~contributing~~gas towells ~~the decline~~ in ~~sales volumes were adjustments to accruals for prior periods that were reversed in the three months ended June 30,~~ 2013~~. Further~~, ~~the~~partially ~~sales~~offset ~~volumes~~by ~~from wells producing at June 30, 2013 declined due to the~~ natural production ~~decline~~declines offor ~~oil~~existing ~~and gas~~ wells. ~~This natural production decline was offset by the drilling of new wells.~~

Oil and Natural Gas Sales. During the three months ended ~~June~~September 30, 2013, we had oil and natural gas sales of $3.54 million, as compared to $42.18 million during the three months ended ~~June~~September 30, 2012. This ~~the~~increase ~~decline~~ is ~~partially~~primarily attributable to ~~our former Wolfberry assets, which were sold effective August 1, 2012, which contributed approximately $230,000 to revenue in~~ the ~~three~~bringing ~~months~~online ~~ended~~of ~~June~~new ~~30,~~oil ~~2012. Also~~and ~~contributing~~gas towells ~~the decline~~ in ~~sales volumes were adjustments to accruals for prior periods that were reversed in the three months ended June 30,~~ 2013~~. Further~~, ~~the~~partially ~~sales~~offset ~~volumes~~by ~~from wells producing at June 30, 2013 declined due to the~~ natural production ~~decline~~declines offor ~~oil~~existing ~~and gas~~ wells. ~~This natural production decline was offset by the drilling of new wells.~~

Costs and Expenses

Operating Costs. During the quarter ended ~~June~~September 30, 2013, we incurred operating costs of $0.95 million, as compared to $0.27 million during the quarter ended ~~June~~September 30, 2012. ~~The increase in operating costs is attributable to higher costs associated with workover activity at our Tom Tom field.~~

Production Taxes. Production taxes were $0.34 million for the quarter ended ~~June~~September 30, 2013, as compared to $0.42 million for the quarter ended ~~June~~September 30, 2012.

Depreciation, Depletion, Amortization and Impairment. For the quarter ended ~~June~~September 30, 2013, depreciation, depletion, amortization, and impairment was $1.71 million, as compared to $21.83 million for the quarter ended ~~June~~September 30, 2012. ~~The decrease in depreciation, depletion, amortization, and impairment was attributable to an impairment charge of $1.8 million related to our Wolfberry assets during the quarter ended June 30, 2012.~~

General and Administrative Expense. General and administrative expense was $0.3 million for the quarter ended ~~June~~September 30, 2012, as compared to $1.65 million for the quarter ended ~~June~~September 30, 2012. The decrease was a result of personnel costs, change of control expenses, and professional fees being lower in the three months ended ~~June~~September 30, 2013 as compared to the three months ended ~~June~~September 30, 2012.

22Other Expense / Income. Other expense was $0.5 million for the quarter ended September 30, 2013, as compared to income of $0.6 million for the quarter ended September 30, 2012. The decrease in income is due to non-cash losses on derivatives contracts.

~~Other~~Nine ~~Expense~~Months /Ended ~~Income. Other~~September ~~expense was $0.05 million for the quarter ended June~~ 30, 2013, asCompared ~~compared~~ to ~~income~~Nine ofMonths ~~$1.3~~Ended ~~million~~September ~~for the quarter ended June~~ 30, 2012~~. The decrease in income is due to non-cash losses on derivatives contracts.~~

~~Six~~The ~~Months~~following ~~Ended~~table ~~June~~sets 30forth summary information regarding our oil and natural gas sales, ~~2013~~net ~~Compared~~production tosold, ~~Six~~average ~~Months~~sales ~~Ended~~prices ~~June~~and production costs and expenses for the nine months ended September 30, 2013 and 2012.

The following table sets forth summary information regarding our oil and natural gas sales, net production sold, average sales prices and production costs and expenses for the six months ended June 30, 2013 and 2012.

	Nine Months Ended September 30,
	2013		2012
(dollars in thousands, except per unit prices)
Revenue
Total Sales	$	10,224,147	$	10,532,615
Salt Water Disposal Sales		158,288		0
Oil and Natural Gas Sales		10,065,859		10,532,615

Net Production sold
Oil (Bbl)		94,957		105,155
Natural gas (Mcf)		231,420		172,833
Total (Boe)		133,527		133,961
Total (Boe/d) (1)		489		491

Average sales prices
Oil ($/Bbl)	$	92.27	$	89.88
Natural gas ($/Mcf)		4.96		4.47
Total average price ($/Boe)	$	75.32	$	80.07

Costs and expenses (per Boe)
Operating costs	$	13.97	$	10.28
Production taxes		5.87		5.58
Depreciation, depletion, and amortization		29.03		21.47
Accretion of discount on asset retirement obligation		0.82		0.39
General and administrative expense		6.35		20.41

	Six Months Ended June 30,
	2013		2012
(dollars in thousands, except per unit prices)
Revenue
Oil and natural gas sales	$	6,794,047	$	7,721,391
Net Production sold
Oil (Bbl)		61,923		74,521
Natural gas (Mcf)		133,618		113,491
Total (Boe)		84,192		96,436
Total (Boe/d) (1)		465		487
Average sales prices
Oil ($/Bbl)	$	86.40	$	93.04
Natural gas ($/Mcf)		5.41		5.30
Total average price ($/Boe)	$	80.70	$	80.07
Costs and expenses (per Boe)
Operating costs	$	15.91	$	13.42
Production taxes		4.61		5.66
Depreciation, depletion, and amortization		33.19		34.34
Accretion of discount on asset retirement obligation		0.85		0.36
General and administrative expense		7.08		23.16

_______________

(1) Boe/d is calculated based on actual calendar days during the period.

~~Six months Revenues and Sales Volumes~~21

~~Oil and Natural Gas Sales Volumes. During the six~~ Nine months ~~ended~~Revenues June 30, 2013, we had total sales volumes of 84,192 Boe, compared to total sales volumes of 96,436 Boe during the six months ended June 30, 2012. This decline is partially attributable to our former Wolfberry assets, which were sold effective August 1, 2012, which contributed approximately 5,100 Boe to sales volumes during the six months ended June 30, 2012. Also contributing to the decline in sales volumes were adjustments to accruals for prior periods that were reversed in the six months ended June 30, 2013. Further, the sales volumes from wells producing at June 30, 2013 declined due to the natural production decline of oil and ~~gas~~Sales ~~wells. This natural production decline was offset by the drilling of new wells.~~Volumes

Oil and Natural Gas Sales. Volumes. During the ~~six~~nine months ended ~~June~~September 30, 2013, we had ~~oil~~total ~~and natural gas~~ sales volumes of ~~$6.8~~133,527 ~~million~~Boe, as compared to ~~$7.7~~total ~~million~~sales ~~during~~volumes ~~the~~of ~~six months ended June 30~~133,961 ~~2012~~Boe ~~the~~during ~~decline is partially attributable to our former Wolfberry assets, which were sold effective August 1, 2012, which contributed approximately $460,000 to revenue in~~ the ~~six~~nine months ended ~~June~~September 30, 2012. Also contributing to the decline in sales volumes were adjustments to accruals for prior periods that were reversed in the six months ended June 30, 2013. Further, the sales volumes from wells producing at June 30, 2013 declined due to the natural production decline of oil and gas wells. This natural production decline was offset by the drilling of new wells.

Oil and Natural Gas Sales. During the nine months ended September 30, 2013, we had oil and natural gas sales of $10.1 million, as compared to $10.5 million during the nine months ended September 30, 2012.

Costs and Expenses

Operating Costs. During the ~~six~~nine months ended ~~June~~September 30, 2013, we incurred operating costs of $1.49 million, as compared to $1.07 million during the ~~six~~nine months ended ~~June~~September 30, 2012. ~~The increase in operating costs is attributable to higher costs associated with workover activity at our Tom Tom field.~~

Production Taxes. Production taxes were $0.48 million for the ~~six~~nine months ended ~~June~~September 30, 2013, as compared to $0.57 million for the ~~quarter~~nine months ended ~~June~~September 30, 2012, which is attributable to higher production in the ~~six~~nine months ended ~~June~~September 30, ~~2012~~2013.

23Depreciation, Depletion, Amortization and Impairment. For the nine months ended September 30, 2013, depreciation, depletion, amortization, and impairment was $3.9 million, as compared to $2.8 million for the nine months ended September 30, 2012.

~~Depreciation,~~General ~~Depletion,~~and ~~Amortization~~Administrative Expense. General and ~~Impairment~~administrative expense was $0. ~~For~~8 million for the ~~six~~nine months ended ~~June~~September 30, 2013, ~~depreciation, depletion, amortization, and impairment was $2.8 million,~~ as compared to $32.37 million for the ~~quarter~~nine months ended ~~June~~September 30, 2012. The decrease ~~in depreciation, depletion, amortization, and impairment~~ was ~~attributable~~a toresult anof ~~impairment~~personnel ~~charge~~costs, change of ~~$1.8~~control ~~million~~expenses, ~~related~~and toprofessional ~~our~~fees ~~Wolfberry~~being ~~assets~~lower ~~during~~in the ~~six~~nine months ended ~~June~~September 30, ~~2012,~~2013 ~~which~~as ~~did~~compared ~~not~~to ~~recur in~~ the ~~six~~nine months ended ~~June~~September 30, ~~2013~~2012.

~~General~~Other ~~and~~Expense ~~Administrative~~/ ~~Expense~~Income. ~~General~~ Other ~~and~~income ~~administrative expense~~ was $0.604 million for the ~~six~~nine months ended ~~June~~September 30, 2013, as compared to expense of $20.204 million for the six months ended ~~June~~September 30, 2012. ~~The decrease was a result of personnel costs, change of control expenses, and professional fees being lower in the six months ended June 30, 2013 as compared to the six months ended June 30, 2012.~~

Other Expense / Income. Other expense was $0.5 million for the six months ended June 30, 2013, as compared to income of $0.5 million for the six ended June 30, 2012.

Liquidity and Capital Resources

General

Our primary sources of liquidity are cash flow from operations and borrowings under our line of credit. Our ability to fund planned capital expenditures and to make acquisitions depends upon our future operating performance, availability of borrowings under our line of credit and availability of equity and debt financing, which is affected by prevailing economic conditions in our industry and financial, business and other factors, some of which are beyond our control. Our cash flow from operations is mainly influenced by the prices we receive for our oil and natural gas production and the quantity of oil and natural gas we produce. Prices for oil and natural gas are affected by national and international economic and political conditions, national and global supply and demand for hydrocarbons, seasonal weather influences and other factors beyond our control.

Capital Expenditures

Most of our capital expenditures are for the exploration, development, and production of oil and natural gas reserves. For the ~~six~~nine months ended ~~June~~September 30, 2013, we had capital expenditures of approximately $6.9 million for the development of oil and natural gas properties. We anticipate capital expenditures of between 8$2 million and 12$3 million for the remainder of 2013. See “Planned Operations” for more information about our planned capital expenditures.

Liquidity

At ~~June~~September 30 2013, we had approximately $73978,000 in cash and cash equivalents and $12.2 million outstanding under our line of credit with Independent Bank. At ~~June~~September 30, 2013, we had a working capital deficit of $~~1.3~~403,614 ~~million~~ compared to a working capital deficit of $3.3 million at December 31, 2012.

On February 5, 2013, we entered into a Senior First Lien Secured Credit Agreement with Independent Bank. Our initial draw on the line of credit was $8.9 million which was primarily used to pay off the Texas Capital Bank line of credit principal and accrued interest. On February 28, 2013, we drew $2,000,000 and on May 24, 2013, we drew a further $1,300,000 on the line of credit and used those funds to pay accounts payable related to the drilling program. As of June 30, 2013, the Credit Agreement balance was $12,200,000, leaving no availability.22

In February 2013, we settled certain creditors liability for $633,975 in cash and by arranging for our largest shareholder, Red Mountain Resources, Inc., to issue the creditors an aggregate of 745,854 shares of its common stock. Further, the holder of the subordinated unsecured debt elected to convert the entire principal and accrued interest balance of the notes into 611,630 shares of our common stock.

Cash Flows

Net cash provided by operating activities was $5.49 million for the ~~six~~nine months ended ~~June~~September 30, 2013, compared to net cash provided by operating activities of $45.39 million for the ~~six~~nine months ended ~~June~~September 30, 2012. The increase in net cash provided by operating activities was primarily due to a $2.08 million profit and $24.87 million of non-cash depreciation, depletion, amortization and impairment, offset by ($0.8 million) of accounts receivable.

24Net cash used in investing activities decreased to $8.0 million for the nine months ended September 30, 2013 from $8.7 million for the nine months ended September 30, 2012.

~~Net~~During the nine months ended September 30, 2013, net cash ~~used~~provided inby ~~investing~~financing activities ~~decreased~~was $2.8 million, as compared to $62.8 million ~~for~~during the ~~six~~nine months ended ~~June~~September 30, ~~2013~~2012. Net ~~from~~cash ~~$7.9~~provided ~~million~~by ~~for~~financing activities during the ~~six~~nine months ended ~~June~~September 30, ~~2012~~2013 ~~due~~was toprimarily acomprised ~~decrease~~of in$12.2 ~~capital~~million ~~expenditures~~drawn under our Independent Bank line of credit, offset by repayments of our Texas Capital Bank line of credit of $8.75 million, and cash repayments to creditors of $0.7 million.

During the six months ended June 30, 2013, net cash provided by financing activities was $1.3 million, as compared to $3.5 million during the six months ended June 30, 2012. Net cash provided by financing activities during the six months ended June 30, 2013 was primarily comprised of $12.2 million drawn under our Independent Bank line of credit, offset by repayments of our Texas Capital Bank line of credit of $8.75 million, repayments of notes of $0.8 million, and repayments to creditors of $1.3 million.

Indebtedness

Notes Payable- Green Shoe

In connection with the merger, the Company, as the accounting acquirer, assumed an unsecured loan from Green Shoe Investments Ltd. (“Green Shoe”) in the principal amount of $487,000 at an interest rate of 5.0%

The debt and associated accrued interest were not repaid at maturity on September 30, 2012. On October 22, 2012, the Company received notice from the lender’s counsel that it would be considered in default on the note beginning November 1, 2012 if the note and accrued interest were not paid in full. From November 1, 2012, the note began to accrue interest at the default rate of 18%. On November 30, 2012, Jackson Street Investors, LLC purchased the note from Green Shoe Investments. Subsequently, on December 12, 2012, Red Mountain Resources, Inc. purchased the note from Jackson Street Investors, LLC. As of December 31, 2012, the note had a principal balance of $367,309 and an accrued interest balance of $62,924.

On February 28, 2013, the Company’s Board of Directors approved a resolution to modify the terms of the note so that the conversion price was reduced from $4.00 to $1.50 per share. On February 28, 2013, Red Mountain Resources, Inc. converted the principal balance of $367,309 and accrued interest balance of $73,611 into 293,947 shares of the Company’s common stock. Accordingly, at June 30, 2013, the balance of the note was zero.23

On February 28, 2013, the Company’s Board of Directors approved a resolution to modify the terms of the note so that the conversion price was reduced from $4.00 to $1.50 per share. On February 28, 2013, Red Mountain Resources, Inc. converted the principal balance of $367,309 and accrued interest balance of $73,611 into 293,947 shares of the Company’s common stock. Accordingly, at September 30, 2013, the balance of the note was zero.

Notes Payable- Little Bay

In connection with the merger, the Company, as the accounting acquirer, assumed an unsecured loan from Little Bay Consulting SA (“Little Bay”) in the principal amount of $520,000 at an interest rate of 5%.

25Beginning March 31, 2011 (the effective date of the Promissory Note), the amounts owed under the Promissory Note began to accrue interest at a rate of 9.99%, and the Promissory Note provided that no payments of principal or interest were due until the maturity date of September 30, 2012. The Company is obligated to pay all accrued interest and make a principal payment equal to one-third of the principal owed upon the closing of an equity offering resulting in a specified amount of net proceeds to the Company. In addition, Little Bay was granted the right to convert the principal and interest owed into shares of common stock of the Company at a conversion price of $4.00 per share. The principal balance of the note as of September 30, 2012 was $396,969.

Beginning March 31, 2011 (the effective date of the Promissory Note), the amounts owed under the Promissory Note began to accrue interest at a rate of 9.99%, and the Promissory Note provided that no payments of principal or interest were due until the maturity date of September 30, 2012. The Company is obligated to pay all accrued interest and make a principal payment equal to one-third of the principal owed upon the closing of an equity offering resulting in a specified amount of net proceeds to the Company. In addition, Little Bay was granted the right to convert the principal and interest owed into shares of common stock of the Company at a conversion price of $4.00 per share. The principal balance of the note as of September 30, 2012 is $396,969.

The debt and associated accrued interest were not repaid at maturity on September 30, 2012. On October 22, 2012, the Company received notice from the lender’s counsel that it would be considered in default on the note beginning November 1, 2012 if the note and accrued interest were not paid in full. From November 1, 2012, the note began to accrue interest at the default rate of 18%. On November 30, 2012, Jackson Street Investors, LLC purchased the note from Little Bay Consulting, S.A. Subsequently, on December 12, 2012, Red Mountain Resources, Inc. purchased the note from Jackson Street Investors, LLC. As of December 31, 2012, the note had a principal balance of $396,969 and an accrued interest balance of $68,005.

On February 28, 2013, the Company’s Board of Directors approved a resolution to modify the terms of the note so that the conversion price was reduced from $4.00 to $1.50 per share. On February 28, 2013, Red Mountain Resources, Inc. converted the principal balance of $396,969 and accrued interest balance of $79,555 into 317,683 shares of the Company’s common stock. Accordingly, at ~~June~~September 30, 2013, the balance of the note was zero.

Line of Credit

As of December 31, 2011, the borrowing base on the Texas Capital Bank (“TCB”) line of credit was $4,500,000. Effective March 1, 2012, the borrowing base was increased to $9,500,000. The interest rate was calculated at the greater of the adjusted base rate or 4%. The line of credit was collateralized by producing wells and was to mature on January 14, 2014. As the result of the sale of certain interests in oil and gas properties, effective August 1, 2012, the borrowing base was reduced by $750,000 and that amount was repaid to TCB out of the sale proceeds.

On February 5, 2013, the Company entered into a Senior First Lien Secured Credit Agreement with Red Mountain Resources, Inc., Black Rock Capital, Inc. and RMR Operating, LLC and Independent Bank, as Lender. Red Mountain owns approximately 85% of the outstanding common stock of Cross Border and Black Rock and RMR Operating are wholly owned subsidiaries of Red Mountain. On February 5, 2013, the Company drew $8,900,000 on the line of credit and used a portion of that draw to fully pay down the TCB line of credit. On February 28, 2013, the Company drew $2,000,000 and on May 24, 2013, the Company drew a further $1,300,000 on the line of credit and used those funds to pay outstanding accounts payable related to our drilling program. As of ~~June~~September 30, 2013, the Credit Agreement balance was $12,200,000, leaving $~~200~~7,8000,000 available.

Off-Balance Sheet Arrangements

As of ~~June~~September 30, 2013, we did not have any off-balance sheet arrangements as defined by Regulation S-K.

Forward-Looking Statements

This Quarterly Report on Form 10-Q contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Statements that are not historical facts, including statements about our beliefs and expectations, are forward-looking statements. Forward-looking statements include statements preceded by, followed by or that include the words “may,” “could,” “would,” “should,” believe,” “expect,” anticipate,” “plan,” “estimate,” “target,” “project,” or “intend” or similar expressions and the negative of such words and expressions, although not all forward-looking statements contain such words or expressions.

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Forward-looking statements are only predictions and are not guarantees of performance. These statements generally relate to our plans, objectives and expectations for future operations and are based on management’s current beliefs and assumptions, which in turn are based on its experience and its perception of historical trends, current conditions and expected future developments as well as other factors it believes are appropriate under the circumstances. Although we believe that the plans, objectives and expectations reflected in or suggested by the forward-looking statements are reasonable, there can be no assurance that actual results will not differ materially from those expressed or implied in such forward-looking statements. Forward-looking statements also involve risks and uncertainties. Many of these risks and uncertainties are beyond our ability to control or predict and could cause results to differ materially from the results discussed in such forward-looking statements. Such risks and uncertainties include, but are not limited to, the following:

·	our ability to raise additional capital to fund future capital expenditures;

·	our ability to generate sufficient cash flow from operations, borrowings or other sources to enable us to fully develop and produce our oil and natural gas properties;

·	declines or volatility in the prices we receive for our oil and natural gas;

·	general economic conditions, whether internationally, nationally or in the regional and local market areas in which we do business;

·	risks associated with drilling, including completion risks, cost overruns and the drilling of non-economic wells or dry holes;

·	uncertainties associated with estimates of proved oil and natural gas reserves;

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

·	risks and liabilities associated with acquired companies and properties;

·	risks related to integration of acquired companies and properties;

·	potential defects in title to our properties;

·	cost and availability of drilling rigs, equipment, supplies, personnel and oilfield services;

·	geological concentration of our reserves;

·	environmental or other governmental regulations, including legislation of hydraulic fracture stimulation;

·	our ability to secure firm transportation for oil and natural gas we produce and to sell the oil and natural gas at market prices;

·	exploration and development risks;

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

·	our ability to retain key members of our management team;

·	weather conditions;

·	actions or inactions of third-party operators of our properties;

·	costs and liabilities associated with environmental, health and safety laws;

·	our ability to find and retain highly skilled personnel;

·	operating hazards attendant to the oil and natural gas business;

·	competition in the oil and natural gas industry; and

·	the other factors discussed under Item 1A. “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2012.

Forward-looking statements speak only as of the date hereof. All such forward-looking statements and any subsequent written and oral forward-looking statements attributable to us or any person acting on our behalf are expressly qualified in their entirety by the cautionary statements contained or referred to in this section and any other cautionary statements that may accompany such forward-looking statements. Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Interest Rate Risk

On February 5, 2013, we entered into the Credit Facility, which exposes us to interest rate risk associated with interest rate fluctuations on outstanding borrowings. At ~~June~~September 30, 2013, we had $12.2 million in outstanding borrowings under the Credit Facility. We incur interest on borrowings under the Credit Facility at a rate per annum equal to the greater of (x) the U.S. prime rate as published in The Wall Street Journal’s “Money Rates” table in effect from time to time and (y) 4.0% (4.0 % at ~~June~~September 30, 2013). A hypothetical 10% change in the interest rates we pay on our borrowings under the Credit Facility as of ~~June~~September 30, 2013 would result in an increase or decrease in our interest costs of approximately $49,000 per year.

Item 4.

Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Disclosure controls and procedures are controls and other procedures that are designed to ensure that information required to be disclosed by us in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the Securities and Exchange Commission’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed in the reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives.

Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we evaluated the effectiveness of our disclosure controls and procedures as of ~~June~~September 30, 2013. Based on that evaluation, and as a result of the material weaknesses described in our Annual Report on Form 10-K for the fiscal year ended December 31, 2012, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were not effective at the reasonable assurance level.

Changes in Internal Control Over Financial Reporting

There have been no changes in our internal control over financial reporting that occurred during the three months ended ~~June~~September 30, 2013 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings

Please see Note 10 to our unaudited notes to financial statements appearing elsewhere in this Quarterly Report on Form 10-Q.

Item 1A. Risk Factors

There have been no material changes to the risk factors discussed in our Annual Report on Form 10-K for the year ended December 31, 2012.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

Dated: August 19, 2013
Dated: November 26, 2013
	By:	/s/ Earl M. Sebring
		Earl M. Sebring
		Interim President
	By:	/s/ Kenneth S. Lamb
		Kenneth S. Lamb
		Chief Accounting Officer, Secretary, and Treasurer

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EXHIBIT INDEX

Exhibit No.		Name of Exhibit
31.1		Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. (*)
31.2		Certification of Principal Accounting Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. (*)
32.1		Certification of Principal Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. (*)
32.2		Certification of Principal Accounting Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. (*)
101.INS**		XBRL Instance Document
101.SCH**		XBRL Taxonomy Extension Schema Document
101.CAL**		XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF**		XBRL Taxonomy Extension Definition Linkbase Document
101.LAB**		XBRL Taxonomy Extension Label Linkbase Document
101.PRE**		XBRL Taxonomy Extension Presentation Linkbase Document

*	Filed herewith.

**	As provided in Rule 406T of Regulation S-T, this information shall not be deemed “filed” for purposes of Section 11 and 12 of the Securities Act of 1933 and Section 18 of the Securities Exchange Act of 1934 or otherwise subject to liability under those sections.

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