UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

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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 March 31, 2014

 

OR

 

o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the transition period from ______________to ______________

 

Commission File Number 000-52738

 

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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)

 

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Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

☒ Yes ☐ No

 

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

☒ Yes ☐ 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).

☐ Yes ☒ 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 May 19, 2014, the Registrant had 17,336,226 shares of common stock outstanding.

 

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DOCUMENTS INCORPORATED BY REFERENCE

 

None.

 

 

TABLE OF CONTENTS

 

PART I. FINANCIAL INFORMATION

 

Item 1.	Financial Statements	3
	Unaudited Balance Sheets as of March 31, 2014 and December 31, 2013	3
	Unaudited Statements of Operations for the Three Months Ended March 31, 2014 and March 31, 2013	5
	Unaudited Statements of Cash Flows for the Three Months Ended March 31, 2014 and March 31, 2013	6
	Unaudited Notes to Financial Statements	7
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	15
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	20
Item 4.	Controls and Procedures	21
PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	22
Item 1A.	Risk Factors	22
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	22
Item 3.	Defaults Upon Senior Securities	22
Item 4.	Mine Safety Disclosures	22
Item 5.	Other Information	22
Item 6.	Exhibits	24

 

  

PART I. FINANCIAL INFORMATION

 

Item 1.   Financial Statements

 

Cross Border Resources, Inc.

Balance Sheets

 

		March 31,				December 31,
		2014				2013
ASSETS
Current Assets
Cash and Cash Equivalents		$	27,299			$	726,239
Accounts Receivable – Oil and Natural Gas Sales			1,973,367				2,086,239
Accounts Receivable – Related Party			1,915,797				24,630
Prepaid Expenses & Other Current Assets			83,604				87,443
Current Tax Asset			19,600				19,600
Total Current Assets			4,019,667				2,944,151
Oil and Gas Properties			57,026,296				56,561,040
Less: Accumulated Depletion, Amortization, and Impairment			(22,077,562)				(20,941,867	)
Net Oil and Gas Properties			34,948,734				35,619,173
Other Assets
Other Property and Equipment, net of Accumulated Depreciation of $100,489 and $95,828 in 2014 and 2013, respectively			29,981				34,641
Restricted Cash			206,087				206,087
Deferred financing costs			80,310				91,242
Other Assets			54,324				54,324
Total Other Assets			370,702				386,294
TOTAL ASSETS		$	39,339,103			$	38,949,618

 

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

 

 

 

Cross Border Resources, Inc.

Balance Sheets - Continued

  

		March 31,				December 31,
		2014				2013
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts Payable - Trade		$	419,311			$	1,268,257
Accrued Expenses & Other Payables			76,173				63,101
Derivative Liability			75,148				38,109
Environmental Liability – Current Portion			1,400,000				1,400,000
Asset Retirement Obligation – Current Portion			562,000				562,000
Deferred Tax Liability			19,600				19,600
Total Current Liabilities			2,552,232				3,351,067
Non-Current Liabilities
Asset Retirement Obligations, Net of Current Portion			2,989,395				2,952,898
Environmental Liability, Net of Current Portion			677,306				687,973
Line of Credit			12,200,000				12,200,000
Total Non-Current Liabilities			15,866,701				15,840,871
Total Liabilities			18,418,933				19,191,938
Commitments & Contingencies (Note 8)
Stockholders’ Equity
Common Stock ($0.001 par value; 99,000,000 shares authorized and 17,336,226 issued and outstanding as of March 31, 2014 and as of December 31, 2013, respectively)			17,336				17,336
Additional Paid in Capital			33,462,473				33,462,473
Accumulated Deficit			(12,559,639	)			(13,722,129	)
Total Stockholders’ Equity			20,920,170				19,757,680
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY		$	39,339,103			$	38,949,618

 

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

 

 

 Cross Border Resources, Inc.

Statements of Operations

 

		Three Months Ended March 31,
		2014				2013
Revenues
Oil and gas sales		$	3,496,782			$	3,332,797
Expenses:
Operating costs			473,192				450,826
Natural gas marketing and transportation expenses			24,623				—
Production taxes			263,811				134,013
Depreciation, depletion, amortization, and Impairment			1,140,355				1,115,502
Accretion expense			36,648				34,979
General and administrative			209,960				322,825
Total expense			2,148,589				2,058,145
Income from operations			1,348,193				1,274,652
Other income (expense):
Gain (loss) on derivatives			(50,653	)			(130,192	)
Gain on settlement of debt			—				858,452
Interest expense			(135,049	)			(185,169	)
Total other income (expense)			(185,702	)			543,091
Income before income taxes			1,162,491				1,817,743
Current tax benefit			—				—
Deferred tax expense			—				—
Income tax expense			—				—
Net income		$	1,162,491			$	1,817,743
Net income per share:
Basic		$	0.07			$	0.11
Fully diluted		$	0.06			$	0.09
Weighted average shares outstanding:
Basic			17,336,226				16,658,198
Fully diluted			21,023,726				20,345,698

 

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

 

 

Cross Border Resources, Inc.

Statements of Cash Flows

 

		Three Months Ended March 31,
		2014				2013
CASH FLOWS FROM OPERATING ACTIVITIES
Net income		$	1,162,491			$	1,817,743
Adjustments to reconcile net income (loss) to cash used by operating activities:
Depreciation, depletion, amortization, and impairment			1,135,696				1,115,502
Settlement of environmental liability			(10,667	)			—
Accretion of asset retirement obligations			36,648				34,979
Amortization of and deferred financing costs			10,933				74,818
Change in derivative instruments			37,039				210,754
Changes in operating assets and liabilities:
Accounts receivable			112,872				(565,743	)
Accounts receivable – related party			(1,891,167)				—
Prepaid expenses and other current assets			1,724				203,556
Accounts payable			(848,946	)			(298)
Accrued expenses			19,693				695,293
Interest payable			—				(130,929)
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES			(233,685)				3,455,675
CASH FLOWS USED IN INVESTING ACTIVITIES
Capital expenditures - oil and gas properties			(465,255	)			(3,402,272	)
NET CASH USED IN INVESTING ACTIVITIES			(465,255	)			(3,402,272	)
CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings on line of credit			—				10,900,000
Payments on line of credit			—				(8,750,000)
Repayments of notes payable			—				(764,278	)
Repayments to creditors			—				(1,352,783	)
NET CASH PROVIDED BY FINANCING ACTIVITIES			—				32,939
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS			(698,940)				86,342
Cash and cash equivalents, beginning of period			726,239				241,561
Cash and cash equivalents, end of period		$	27,299			$	327,903
Supplemental disclosures of cash flow information:
Interest paid		$	124,116			$	82,726
Income taxes paid		$	—			$	—
NON-CASH TRANSACTIONS
Issuance of common stock to settle liability		$	—			$	692,967
Additions of ARO		$	36,648			$	10,000

 

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

 

 

Cross Border Resources, Inc.

Notes to Financial Statements

 

1.   Organization

 

Nature of Operations

 

Cross Border Resources, Inc. (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 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.

 

The interim financial statements are condensed and should be read in conjunction with the company’s latest annual financial statements and interim disclosures generally do not repeat those in the annual statements.

 

2.   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 March 31, 2014 and December 31, 2013.

 

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 March 31, 2014 or December 31, 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 March 31, 2014, 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 March 31, 2014 or December 31, 2013.

 

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 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 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 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 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.

 

3 – Asset retirement obligations

 

The following is a description of the changes to the Company’s asset retirement obligations for the periods ended March 31, 2014 and December 31, 2013:

 

		March 31,				December 31,
		2014				2013
Asset retirement obligations at beginning of year		$	3,515,728			$	3,317,358
Settlement of liabilities			—				(1,284	)
Revision of previous estimates			(978)				—
Accretion expense			36,648				148,364
Additions			—				51,290
Asset retirement obligations at end of period		$	3,551,395			$	3,515,728
Less: current portion			562,000				562,000
Long-term portion		$	2,989,395			$	2,952,898

 

 

4 – 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:

 

		March 31,			December 31,
		2014			2013
Oil and natural gas properties		$	57,026,296		$	56,561,040
Less accumulated depletion and impairment			(22,077,562	)		(20,941,867	)
Net oil and natural gas properties capitalized costs		$	34,948,734		$	35,619,173

 

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:

 

		March 31,			December 31,
		2014			2013
Other property and equipment		$	130,470		$	130,470
Less accumulated depreciation			(100,489	)		(95,828	)
Net property and equipment		$	29,981		$	34,641

 

5 – 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.

 

Stock Options

 

In 2011, the Company issued options to purchase 85,000 shares of its common stock at $4.80 to its directors.  For the three months ended March 31, 2014, there was no stock based compensation.

 

Stock option activity summary is presented in the table below:

 

								Weighted-
								average
					Weighted-			Remaining
					average			Contractual
		Number of			Exercise			Term
		Shares			Price			(years)
Outstanding and exercisable December 31, 2012		87,500		$	4.80			4.08
Granted		—			—			—
Cancelled		—			—			—
Exercised		—			—			—
Forfeited		—			—			—
Expired		—			—			—
Outstanding and exercisable at December 31, 2013		87,500			4.80			3.08
Granted		—			—			—
Cancelled		—			—			—
Exercised		—			—			—
Forfeited		—			—			—
Expired		—			—			—
Outstanding and exercisable at March 31, 2014		87,500		$	4.80			2.83

 

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

 

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 the Company has sufficient information to make more refined estimates on the estimated life of 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 8, 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 RMR issuing its shares to the creditors payable, the Company issued RMR 422,650 shares of its common stock.

 

 

Conversion of Notes Payable

 

On February 28, 2013, RMR, 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 RMR.

 

6 – Related party transactions

 

During the year ended December 31, 2013, Red Mountain incurred approximately $3,000,000 for general and administrative expenses and operating costs, all of which was repaid at December 31, 2013. During the three months ended March 31, 2014, the Company advanced Red Mountain approximately $1,900,000 to use for its general and administrative and operating costs. Such funds will be repaid to the Company.

 

7 – Long term debt

 

Operating Line of Credit

 

On February 5, 2013, the Company entered into a Senior First Lien Secured Credit Agreement with RMR, Black Rock Capital, Inc. and RMR Operating, LLC and Independent Bank, as Lender. RMR owns approximately 85% of the outstanding common stock of Cross Border and Black Rock and RMR Operating are wholly owned subsidiaries of 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.

 

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 March 31, 2014, the creditors had borrowed a total of $23,800,000. As of March 31, 2014, the borrowing base was $30,000,000 million, leaving $6,200,000 of availability.

 

8 – Commitments and contingencies

 

Litigation

 

The Company, the Company’s former Chief Executive Officer, and the Company’s former Chief Operating Officer are party to a lawsuit with a former employee. On May 4, 2011, Clifton M. (Marty) Bloodworth initially filed a lawsuit in the State District Court of Midland County, Texas, against Doral West Corp. d/b/a Doral Energy Corp. (the predecessor entity of Cross Border) (“Doral Energy”) and Everett Willard Gray II, the Company’s former Chief Executive Officer. Mr. Bloodworth later amended his lawsuit to name Horace Patrick Seale, the Company’s former Chief Operating Officer, as an additional defendant. Mr. Bloodworth generally alleges that Mr. Gray and Mr. Seale, as agents 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 Energy, fraud in the inducement and common law fraud, civil conspiracy, breach of fiduciary duty, and violation of the Texas Deceptive Trade Practices Act. Mr. Bloodworth is seeking damages of approximately $280,000. Mr. Gray, Mr. Seale 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 that 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 by the Company 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, where KeyBanc filed a counterclaim against the Company. The Company and KeyBanc have each filed motions for summary judgment, requesting the Court to rule in their respective favors. The Company intends to vigorously defend the action.

 

In addition to the foregoing, in the ordinary course of business, the Company is periodically a party to various litigation matters that it does not believe will have a material adverse effect on its results of operations or financial condition.

 

 

Environmental Contingencies

 

The Company is subject to federal and state laws and regulations relating to the protection of the environment. Environmental risk is inherent in all 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 March 31, 2014 and December 31, 2013, the Company had approximately $2.1 million in environmental remediation liabilities related to the Company’s operated Tom Tom and Tomahawk fields located in Chaves and Roosevelt counties in 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 has incurred $11,000 in costs and expects to incur the remaining expenditures over an eighteen month period beginning in April 2014.

 

9 – 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 March 31, 2014, the Company had a net derivative liability of $75,148, as compared to a net derivative liability of $38,109 at December 31, 2013.  The change in net derivative asset/liability is recorded as non-cash mark-to-market income or loss.  Mark-to-market losses of $37,039 were recorded in the three months ended March 31, 2014 as compared to mark-to-market income of $283,831 during the twelve months ended December 31, 2013.  Net realized hedge settlement loss for the three months ended March 31, 2014 was $13,614 as compared to net realized hedge settlement loss of $14,062 for the twelve months ended December 31, 2013.  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 March 31, 2014, the Company had crude oil swaps in place relating to a total of 2,000 Bbls per month, as follows:

 

Price

Volumes

Fair Value of Outstanding Derivative Contracts (1) as of

Transaction

Per

Per

March 31,

December

Date

Type (2)

Beginning

Ending

Unit

Month

2014

31, 2013

November 2011

Swap

12/01/2011

11/30/2014

$93.50

2,000

(75,148)

(62,730)

February 2012

Swap

03/01/2012

02/28/2014

$106.50

1,000

—

24,621

$

(75,148)

$

(38,109)

 

(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.

 

10 – 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 March 31, 2014 and December 31, 2013:

 

		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 March 31, 2014
Liabilities
Environmental liability		$	—			$	—				(2,077,306	)		$	(2,077,306	)
Asset retirement obligations (non-recurring)		$	—			$	—				(3,551,395	)		$	(3,551,395	)
Commodities Derivative		$	—			$	(75,148	)		$	—			$	(75,148	)
Total		$	—			$	(75,148	)		$	(5,628,701	)		$	(5,703,849	)

 

 

		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 December 31, 2013
Liabilities:
Environmental liability		$	—			$	—				(2,087,973	)		$	(2,087,973	)
Commodities derivatives		$	—			$	(38,109	)		$	—			$	(38,109	)
Asset retirement obligations (non-recurring)			—				—				(3,514,898	)			(3,514,898	)
Total		$	—			$	(38,109	)		$	(5,602,871	)		$	(5,640,980	)

 

The following is a summary of changes to fair value measurements using Level 3 inputs during the three months ended March 31, 2014:

 

		Environmental Liability
Balance, December 31, 2013		$	2,086,833
Acquisitions			—
Settlement of liabilities			9,527
Revisions of previous estimates			—
Balance, March 31, 2014		$	2,077,306

 

 

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.  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 83% of our outstanding common stock.  As a result of that transaction, our results are consolidated in Red Mountain Resources, Inc.’s financial statements.

 

First Quarter 2014 Operational Update

 

In the three months ended March 31, 2014, Cross Border produced 536 Boe/d. We did not complete any wells in period.

 

Planned Operations

 

In the next quarter we plan to work over three gross and net wells at Tom Tom. We plan to spend approximately $1.7 million on these workovers. We also plan to drill and complete three gross (0.4 net) non-operated wells. One of these is a 2^nd Bone Spring horizontal well at Turkey Track and the other 2 are vertical Glorieta-Yeso wells at Red Lakes. We plan to spend approximately $1.0 million on these three wells. We expect to have sufficient liquidity to complete our planned operations.

 

 

 

Critical Accounting Policies and Estimates

 

Our discussion and analysis of our financial condition and results of operations is based upon our financial statements, which have been prepared in accordance with U.S. generally accepted accounting principles (“GAAP”). The preparation of these 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 financial statements included in our 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 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 March 31, 2014 or December 31, 2013. 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 March 31, 2013, 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.

 

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 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.

 

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

 

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.

  

 

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 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.

 

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 March 31, 2014 Compared to Three Months Ended March 31, 2013

 

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 March 31, 2014 and 2013.

 

		Three Months Ended March 31,
		2014				2013
(dollars in thousands, except per unit prices)
Revenue
Oil and Gas Sales		$	3,496,782			$	3,332,797
Net Production sold
Oil (Bbl)			33,420				28,026
Natural gas (Mcf)			67,231				89,441
Natural gas liquids (Bbl)			3,648				1,023
Total (Boe)			48,273				43,956
Total (Boe/d) (1)			536				488
Average sales prices
Oil ($/Bbl)		$	89.90			$	95.19
Natural gas ($/Mcf)			5.65				5.03
Natural gas liquids ($/Bbl)			30.82				38.96
Total average price ($/Boe)		$	72.43			$	71.84
Costs and expenses (per Boe)
Operating costs and marketing		$	10.31			$	10.26
Production taxes			5.46				3.05
Depreciation, depletion, and amortization			23.53				25.38
Accretion of discount on asset retirement obligation			0.76				0.80
General and administrative expense			4.35				7.34

 

_________________   

(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 March 31, 2014, we had total sales volumes of 48,273 Boe, compared to total sales volumes of 39,166 Boe during the three months ended March 31, 2013.  This increase is primarily attributable to the bringing online of new oil and gas wells in 2013, partially offset by natural production declines for existing wells.

 

Oil and Natural Gas Sales. During the three months ended March 31, 2014, we had oil and natural gas sales of $3.5 million, as compared to $3.2 million during the three months ended March 31, 2013. This increase is primarily attributable to the bringing online of new oil and gas wells in 2013, partially offset by natural production declines for existing wells.

 

Costs and Expenses  

 

Operating Costs.  During the quarter ended March 31, 2014, we incurred operating costs of $0.5 million, as compared to $0.5 million during the quarter ended March 31, 2013.  

 

Production Taxes.  Production taxes were $0.3 million for the quarter ended March 31, 2014, as compared to $0.1 million for the quarter ended March 31, 2013, primarily as a result of a different product mix between oil and gas.

 

Depreciation, Depletion, Amortization and Impairment.  For the quarter ended March 31, 2014, depreciation, depletion, amortization, and impairment was $1.1 million, as compared to $1.1 million for the quarter ended March 31, 2013.  

 

General and Administrative Expense.  General and administrative expense was $0.2 million for the quarter ended March 31, 2014, as compared to $.3 million for the quarter ended March 31, 2013, primarily due to a decrease in rent expense.  

 

Other Expense / Income.   Other expense was $0.2 million for the quarter ended March 31, 2014, as compared to other income of $0.5 million for the quarter ended March 31, 2014.

 

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 three months ended March 31, 2014, we had capital expenditures of approximately $0.5 million for the development of oil and natural gas properties. We anticipate capital expenditures between 2 million and 3 million for the second quarter of 2014. See “Planned Operations” for more information about our planned capital expenditures.

 

Liquidity

 

At March 31 2014, we had approximately $27,000 in cash and cash equivalents and $12.2 million outstanding under our line of credit with Independent Bank.  At March 31, 2014, we had working capital of approximately $1.5 million compared to a working capital deficit of approximately $1.8 million at March 31, 2013.

 

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.

 

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 March 31, 2014, the borrowers had borrowed $23,800,000 under the Credit Agreement, leaving availability of $6,800,000.

 

 

Cash Flows

 

Net cash used in operating activities was $0.2 million for the three months ended March 31, 2014, compared to net cash provided by operating activities of $3.5 million for the three months ended March 31, 2013.  The decrease in net cash provided by operating activities was primarily due to a $1.2 million profit, $1.1 million of non-cash depletion and depreciation, $0.1 of accounts receivable, offset by ($0.8 million) of accounts payable and ($1.9 million) of accounts receivable related party.

 

Net cash used in investing activities decreased to $0.5 million for the three months ended March 31, 2014 from $3.4 million for the three months ended March 31, 2013 due to fewer wells being drilled in the period ended March 31, 2014 as compared to the period ended March 31, 2013.

 

During the three months ended March 31, 2014, there was no net cash used, nor provided, by financing activities as compared to $32,939 provided by financing activities for the three months ended March 31, 2013.

 

Indebtedness

 

Line of Credit

 

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 March 31, 2014 the borrowers had borrowed $23,800,000 under the Credit Agreement, leaving $6,200,000 available.

 

Off-Balance Sheet Arrangements

 

As of March 31, 2014, 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.

 

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, 2013.

 

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 March 31, 2014, 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 March 31, 2014). A hypothetical 10% change in the interest rates we pay on our borrowings under the Credit Facility as of March 31, 2014 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 March 31, 2014.  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, 2013, 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 March 31, 2014 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

 

 

PART II. OTHER INFORMATION

 

 

Item 1.   Legal Proceedings

 

 

Please see Note 8 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, 2013.

 

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.

 

 

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: May 20, 2014
	By:	/s/ Earl M. Sebring
		Earl M. Sebring
		Interim President
	By:	/s/ Kenneth S. Lamb
		Kenneth S. Lamb
		Chief Accounting Officer, Secretary, and Treasurer

 

 

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