UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

 

FORM 10-Q

 

(Mark One)

 

☒

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

For the quarterly period ended June 30, 2014

 

OR

 

☐

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.

☒ 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 ☐	Accelerated filer ☐
Non-accelerated filer ☐ (Do not check if a smaller reporting company)	Smaller reporting company ☒

 

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 August 19, 2014, 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, 2014 and December 31, 2013	3
	Unaudited Statements of Operations for the Three and Six Months Ended June 30, 2014 and June 30, 2013	5
	Unaudited Statements of Cash Flows for the Six Months Ended June 30, 2014 and June 30, 2013	7
	Unaudited Notes to Financial Statements	8
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	16
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	23
Item 4.	Controls and Procedures	23
PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	24
Item 1A.	Risk Factors	24
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	24
Item 3.	Defaults Upon Senior Securities	24
Item 4.	Mine Safety Disclosures	24
Item 5.	Other Information	24
Item 6.	Exhibits

 

 

PART I. FINANCIAL INFORMATION

 

Item 1.

Financial Statements

 

Cross Border Resources, Inc. 

Balance Sheets

 

		June 30, 2014 (unaudited)				December 31, 2013
ASSETS
Current Assets
Cash and Cash Equivalents		$	904,911			$	726,239
Accounts Receivable – Oil and Natural Gas Sales			2,066,454				2,086,239
Accounts Receivable – Related Party			—				24,630
Prepaid Expenses & Other Current Assets			79,275				87,443
Current Tax Asset			19,600				19,600
Total Current Assets			3,070,240				2,944,151
Oil and Gas Properties			57,420,344				56,561,040
Less: Accumulated Depletion, Amortization, and Impairment			(22,812,843	)			(20,941,867	)
Net Oil and Gas Properties			34,607,501				35,619,173
Other Assets
Other Property and Equipment, net of Accumulated Depreciation of $105,148 and $95,829 in 2014 and 2013, respectively			25,322				34,641
Restricted Cash			233,949				206,087
Deferred financing costs			69,377				91,242
Other Assets			54,324				54,324
Total Other Assets			382,972				386,294
TOTAL ASSETS		$	38,060,713			$	38,949,618

  

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

 

  

		June 30, 2014 (unaudited)				December 31, 2013
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts Payable - Trade		$	726,647			$	1,268,257
Accounts Payable – Related Party			135,167				—
Accrued Expenses & Other Payables			203,085				63,101
Derivative Liability			100,762				38,109
Environmental Liability – Current Portion			2,067,175				1,400,000
Asset Retirement Obligation – Current Portion			1,534,045				562,000
Deferred Tax Liability			19,600				19,600
Total Current Liabilities			4,786,481				3,351,067
Non-Current Liabilities
Asset Retirement Obligations, Net of Current Portion			1,596,432				2,952,898
Environmental Liability, Net of Current Portion			—				687,973
Line of Credit			9,200,000				12,200,000
Total Non-Current Liabilities			10,796,432				15,840,871
Total Liabilities			15,582,913				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 June 30, 2014 and as of December 31, 2013, respectively)			17,336				17,336
Additional Paid in Capital			33,462,473				33,462,473
Accumulated Deficit			(11,002,009	)			(13,722,129	)
Total Stockholders’ Equity			22,477,800				19,757,680
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY		$	38,060,713			$	38,949,618

 

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

 

 

 Cross Border Resources, Inc.

Statements of Operations

 

		Three Months Ended June 30,
		2014 (unaudited)				2013
Revenues
Oil and gas sales		$	3,690,895			$	3,461,249
Expenses:
Operating costs			474,893				891,666
Natural gas marketing and transportation expenses			47,695				42,572
Production taxes			312,213				254,241
Depreciation, depletion, amortization, and Impairment			739,941				1,679,138
Accretion expense			114,437				36,723
General and administrative			223,694				263,407
Total expense			1,912,873				3,167,747
Income from operations			1,778,022				293,502
Other income (expense):
Gain (loss) on derivatives			(82,568	)			107,635
Interest expense			(137,826	)			(160,853	)
Total other income (expense)			(220,394	)			(53,218	)
Income before income taxes			1,557,628				240,284
Current tax benefit			—				—
Deferred tax expense			—				—
Income tax expense			—				—
Net income		$	1,557,628			$	240,284
Net income per share:
Basic			0.09				0.01
Fully diluted		$	0.07			$	0.01
Weighted average shares outstanding:
Basic			17,336,226				17,336,226
Fully diluted			21,023,726				21,023,726

 

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

 

 

Cross Border Resources, Inc.

Statements of Operations

 

		Six Months Ended June 30,
		2014 (unaudited)				2013
Revenues
Oil and gas sales		$	7,187,677			$	6,794,047
Expenses:
Operating costs			948,085				1,339,097
Natural gas marketing and transportation expenses			72,318				49,140
Production taxes			576,024				388,255
Depreciation, depletion, amortization, and impairment			1,880,296				2,794,639
Accretion expense			151,085				71,702
General and administrative			433,656				596,128
Total expense			4,061,464				5,238,961
Income from operations			3,126,213				1,555,086
Other income (expense):
Loss on derivatives			(133,221	)			(22,557	)
Gain on settlement of debt			—				858,452
Interest expense			(272,875	)			(346,022	)
Total other income (expense)			(406,096	)			489,873
Income before income taxes			2,720,117				2,044,959
Current tax benefit			—				—
Deferred tax expense			—				—
Income tax expense			—				—
Net income		$	2,720,117			$	2,044,959
Net income per share:
Basic		$	0.16			$	0.12
Fully diluted		$	0.13			$	0.10
Weighted average shares outstanding:
Basic			17,336,226				16,999,085
Fully diluted			21,023,726				20,686,585

 

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

 

 

Cross Border Resources, Inc. 

Statements of Cash Flows

 

		Six Months Ended June 30,
		2014				2013
CASH FLOWS FROM OPERATING ACTIVITIES
Net income		$	2,720,117			$	2,044,959
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation, depletion, amortization, and impairment			1,880,296				2,794,639
Settlement of environmental liability			(20,798	)			(11,842	)
Settlement of asset retirement obligations			(3,314	)			—
Accretion of asset retirement obligations			151,085				71,702
Amortization of and deferred financing costs			21,865				77,120
Change in derivative instruments			62,653				135,044
Changes in operating assets and liabilities:
Accounts receivable			19,785				(847,051	)
Accounts receivable – related party			(135,269	)			—
Prepaid expenses and other current assets			8,171				119,787
Accounts payable			(541,610	)			445,491
Restricted cash			(27,862	)			—
Accrued expenses			139,982				652,412
Interest payable			—				(130,929	)
NET CASH PROVIDED BY OPERATING ACTIVITIES			4,275,100				5,360,653
CASH FLOWS USED IN INVESTING ACTIVITIES
Capital expenditures - oil and gas properties			(1,391,496	)			(6,862,343	)
NET CASH USED IN INVESTING ACTIVITIES			(1,391,496	)			(6,862,343	)
CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings on line of credit			—				12,200,000
Advances to related party			(2,704,933	)			—
Payments on line of credit			—				(8,750,000	)
Repayments of notes payable			—				(764,278	)
Repayments to creditors			—				(1,352,783	)
NET CASH (USED) PROVIDED BY FINANCING ACTIVITIES			(2,704,933	)			1,332,939
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS			178,671				(168,751	)
Cash and cash equivalents, beginning of period			726,239				241,561
Cash and cash equivalents, end of period		$	904,911			$	72,810
Supplemental disclosures of cash flow information:
Interest paid		$	251,009			$	241,277
Income taxes paid		$	—			$	—
NON-CASH TRANSACTIONS
Revisions of asset retirement obligations		$	(553,457	)		$	—
Additions of asset retirement obligations		$	22,191			$	—
Reduction of principal on line of credit in exchange for advances to related party		$	3,000,000			$	—

 

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 Borders 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.

 

2.   Summary of Significant Accounting Policies

 

Basis of Presentation

 

The Company prepares its financial statements in accordance with accounting principles generally accepted in the United States of America. The accompanying interim unaudited financial statements have been prepared in accordance with generally accepted accounting principles for the interim financial information in accordance with Article 8 or Regulation S-X. Accordingly, they do not include all of the information and footnotes required by generally accepted accounting principles for complete financial statements. In the Company’s opinion, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation have been included. Operating results for the six month period ended June 30, 2014 are not necessarily indicative of the results for the full year. While management of the Company believes that the disclosures presented herein are adequate and not misleading, these interim financial statements should be read in conjunction with the audited financial statements and the footnotes thereto for the periods ended December 31, 2013 filed in its annual report on Form 10-K filed with the Securities and Exchange Commission.

 

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 30, 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 June 30, 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 June 30, 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 June 30, 2014 or December 31, 2013.

 

Other property and equipment

 

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

  

The Company follows 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 2014, FASB issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (ASU 2014-09), which supersedes nearly all existing revenue recognition guidance under U.S. GAAP. The core principle of ASU 2014-09 is to recognize revenues when promised goods or services are transferred to customers in an amount that reflects the consideration to which an entity expects to be entitled for those goods or services. ASU 2014-09 defines a five step process to achieve this core principle and, in doing so, more judgment and estimates may be required within the revenue recognition process than are required under existing U.S. GAAP. The standard is effective for annual periods beginning after December 15, 2016, and interim periods therein, using either of the following transition methods: (i) a full retrospective approach reflecting the application of the standard in each prior reporting period with the option to elect certain practical expedients, or (ii) a retrospective approach with the cumulative effect of initially adopting ASU 2014-09 recognized at the date of adoption (which includes additional footnote disclosures). We are currently evaluating the impact of our pending adoption of ASU 2014-09 on our financial statements and have not yet determined the method by which we will adopt the standard in 2017.

 

 

3 – Asset retirement obligations

 

The following is a description of the changes to the Company’s AROs for the periods ended June 30, 2014 and December 31, 2013:

  

		June 30,				December 31,
		2014				2013
Asset retirement obligations at beginning of period		$	3,514,898			$	3,317,358
Loss on settlement			(926	)			—
Settlement of liabilities			(3,314	)			(2,114	)
Revision of previous estimates			(553,457	)			—
Accretion expense			151,085				148,364
Additions			22,191				51,290
Asset retirement obligations at end of period		$	3,130,477			$	3,514,898
Less: current portion			1,534,045				562,000
Long-term portion		$	1,596,432			$	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:

  

		June 30,			December 31,
		2014			2013
Oil and natural gas properties		$	57,420,344		$	56,561,040
Less accumulated depletion, amortization and impairment			(22,812,843	)		(20,941,867	)
Net oil and natural gas properties capitalized costs		$	34,607,501		$	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:

 

		June 30,				December 31,
		2014				2013
Other property and equipment		$	130,470			$	130,470
Less accumulated depreciation			(105,148	)			(95,829	)
Net property and equipment		$	25,322			$	34,641

 

5 – Stockholders’ equity and earnings per share

 

2011 Equity Financing

 

 

Issuance of Common Shares to Settle Creditors Payable

 

On February 28, 2013, the Company entered into settlement agreements with two of the creditors payable arising out of the 2002 bankruptcy of Pure Energy Group, Inc., the predecessor to the Company. 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, RMR incurred approximately $3,000,000 for general and administrative expenses and operating costs on the Company’s behalf, all of which was repaid at December 31, 2013. Effective June 30, 2014, RMR assumed the Company's obligations with respect to $3,000,000 of the Company's outstanding borrowings under the Credit Facility (as defined below) in exchange for the satisfaction and discharge of a $2,900,000 intercompany payable from RMR to the Company. As of June 30, 2014, the Company owed RMR $135,167 for expenses incurred by RMR on behalf of 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, as borrowers (the “Borrowers”) and Independent Bank, as Lender, providing for an up to $100,000,000 credit facility (the “Credit Facility”). RMR owns approximately 83% 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 its prior 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. Effective June 30, 2014, RMR assumed the Company’s obligations with respect to $3,000,000 of the Company’s outstanding borrowings under the Credit Facility in exchange for the satisfaction and discharge of a $2,900,000 intercompany payable from RMR to the Company.

 

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 June 30, 2014, the borrowers had borrowed a total of $26,800,000. As of June 30, 2014, the borrowing base was $30,000,000 million, leaving $3,200,000 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-Consumer Protection 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. The Company disputes that any Transaction was consummated and that KeyBanc is entitled to any fees or out-of-pocket expenses. The Company filed a complaint seeking (i) a declaration that it is not liable to KeyBanc for any amounts in connection with the Engagement Letter, (ii) attorneys’ fees, and (iii) costs of suit. KeyBanc filed a counterclaim seeking (i) at least $750,000 in compensatory damages, (ii) interest, (iii) expenses and court costs, and (iv) reasonable and necessary attorneys’ fees. The matter was originally filed in the 44th 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 and KeyBanc filed motions for summary judgment. On August 4, 2014, the court granted in part and denied in part KeyBanc’s motion for summary judgment, narrowing the unresolved issue for trial to whether or not RMR’s acquisitions of the Company’s common stock were a “series of related transactions” within the meaning of the Engagement Letter. The matter could go to trial as early as September 2014. 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 June 30, 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 expects to incur the remaining costs during the next year.

 

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 June 30, 2014, the Company had a net derivative liability of $100,762, 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 $62,653 were recorded in the six months ended June 30, 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 six months ended June 30, 2014 was $70,568 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 June 30, 2014 and December 31, 2013, the Company had crude oil swaps in place relating to a total of 2,000 Bbls and 3,000 Bbls, respectively, per month, as follows:

 

Price

Volumes

Fair Value of Outstanding   Derivative Contracts (1) as of

Transaction

Per

Per

June 30,

December 31,

Date

Type (2)

Beginning

Ending

Unit

Month

2014

2013

November 2011

Swap

12/01/2011

11/30/2014

$  93.50

2,000

(100,762)

(62,730)

February 2012

Swap

03/01/2012

02/28/2014

$106.50

1,000

—

24,621

$

(100,762)

$

(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 June 30, 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 June 30, 2014
Liabilities
Environmental liability		$	—			$	—			$	(2,067,175	)		$	(2,067,175	)
Asset retirement obligations (non-recurring)		$	—			$	—			$	(3,130,477	)		$	(3,130,477	)
Commodities Derivative		$	—			$	(100,762	)		$	—			$	(100,762	)
Total		$	—			$	(100,762	)		$	(5,197,652	)		$	(5,298,414	)

 

 

		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, 2013
Assets:
Commodities derivatives		$	—			$	3,504			$	—			$	3,504
Total		$	—			$	3,504			$	—			$	3,504
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 six months ended June 30, 2014:

 

		Environmental Liability
Balance, December 31, 2013		$	2,087,973
Acquisitions			—
Settlement of liabilities			20,798
Revisions of previous estimates			—
Balance, June 30, 2014		$	2,067,175

  

 

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 Apache Corp., Mewbourne Oil Company, Concho Resources Inc., COG Operating LLC, LRE Operating, LLC, XTO Energy Inc., Cimarex Energy Co., and Occidental Petroleum Corporation 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. (“Red Mountain”) closed the acquisition of 5,091,210 shares of our common stock, bringing its total ownership to approximately 78% of the outstanding common stock of the company.  Prior to the acquisition, Red Mountain owned 47% of our outstanding common stock.  As of the date of this report, Red Mountain owns approximately 83% of our outstanding common stock.  As a result of that transaction, our results are consolidated in Red Mountain’s financial statements.

 

Second Quarter 2014 Operational Update

 

During the three months ended June 30, 2014, Cross Border completed three wells (0.4 net). One of these, Zircon 12/7 GF Federal Com 1H, a horizontal 2nd Bone Spring well in the Turkey Track area, was completed in May 2014, and achieved a maximum 24-hour rate of 1,188 Boe/d (89% oil) and a 10-day average rate of 1,028 Boe/d (87% oil). Cross Border owns an approximately 16% working interest and 13% net revenue interest in the well, which is operated by Mewbourne Oil Company. We spudded another well in the Turkey Track area in June, and it was recently completed. This well, Zircon 2 B1EH State 2H, is our first in the area targeting the 1st Bone Spring.

 

We also completed two vertical Yeso wells in the Red Lake area, Southern Union 30G State 3 and Horseshoe State 3. We own approximately 14% working interest and 12% net revenue interest in Southern Union 30G State 3 and approximately 13% working interest and 9% net revenue interest in Horseshoe State 3. Both wells are operated by LRE Operating. Early production rates from the wells were 137 Boe/d (88% oil) and 140 Boe/d (86% oil), respectively.

 

Towards the end of the quarter, we commenced our Tom Tom workover program. The first phase of the first workover was an acid treatment on Strange Federal 1, a well in which we own 100% working interest and approximately 75% net revenue interest. Production increased by approximately 5 Bbl/d in the month following the treatment. The next phase of the workover is a fracture stimulation, which is scheduled for early fiscal 2015.

 

 

Planned Operations

 

In the remainder of 2014, we plan to spend between $7 and $10 million to drill and complete wells, re-enter and complete wells, or improve infrastructure. The majority of this capital will be focused on the Tom Tom area, where we will continue to remediate the field and improve production from existing wells. We plan to reenter 23 wells (20.0 net) in the Tom Tom area. In our non-operated areas, we anticipate completing 6 new wells (0.6 net) before the end of the year. These wells have various targets, including 1^st Bone Spring, 2^nd Bone Spring, 3^rd Bone Spring, and Yeso reservoirs. We expect to finance these activities with cash flow generated from operations and availability under our line of credit with Independent Bank.

 

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 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 2—Summary of Significant Accounting Policies” to our financial statements included in this Quarterly Report on Form 10-Q. 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 June 30, 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 June 30, 2014, 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 2014, FASB issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (ASU 2014-09), which supersedes nearly all existing revenue recognition guidance under U.S. GAAP. The core principle of ASU 2014-09 is to recognize revenues when promised goods or services are transferred to customers in an amount that reflects the consideration to which an entity expects to be entitled for those goods or services. ASU 2014-09 defines a five step process to achieve this core principle and, in doing so, more judgment and estimates may be required within the revenue recognition process than are required under existing U.S. GAAP. The standard is effective for annual periods beginning after December 15, 2016, and interim periods therein, using either of the following transition methods: (i) a full retrospective approach reflecting the application of the standard in each prior reporting period with the option to elect certain practical expedients, or (ii) a retrospective approach with the cumulative effect of initially adopting ASU 2014-09 recognized at the date of adoption (which includes additional footnote disclosures). We are currently evaluating the impact of our pending adoption of ASU 2014-09 on our consolidated financial statements and have not yet determined the method by which we will adopt the standard in 2017.

 

Results of Operations

 

Three Months Ended June 30, 2014 Compared to Three Months Ended June 30, 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 June 30, 2014 and 2013.

 

		Three Months Ended June 30,
		2014				2013
Revenue
Oil and Gas Sales (in thousands)		$	3,691			$	3,461
Net Production sold
Oil (Bbl)			33,250				35,601
Natural gas (Mcf)			77,075				56,550
Natural gas liquids (Bbl)			3,733				1,986
Total (Boe)			49,829				47,012
Total (Boe/d) (1)			554				517
Average sales prices
Oil ($/Bbl)		$	93.19			$	89.34
Natural gas ($/Mcf)			5.99				4.86
Natural gas liquids ($/Bbl)			34.97				25.21
Total average price ($/Boe)		$	74.07			$	73.62
Costs and expenses (per Boe)
Operating costs and marketing		$	9.53			$	18.97
Production taxes			6.27				5.41
Depreciation, depletion, amortization and impairment			14.85				35.72
Accretion of discount on asset retirement obligation			2.30				0.78
General and administrative expense			4.49				5.60

  

(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 30, 2014, we had total sales volumes of 49,829 Boe, compared to total sales volumes of 47,012 Boe during the three months ended June 30, 2013.  This increase is primarily attributable to production from new wells, partially offset by natural decline in production.

 

Oil and Natural Gas Sales. During the three months ended June 30, 2014, we had oil and natural gas sales of $3.7 million, as compared to $3.5 million during the three months ended June 30, 2013. 

 

Costs and Expenses  

 

Operating Costs.  During the three months ended June 30, 2014, we incurred operating costs of $0.5 million, as compared to $0.9 million during the three months ended June 30, 2013.  

 

Production Taxes.  Production taxes were $0.3 million for the three months ended June 30, 2014, as compared to $0.3 million for the three months ended June 30, 2013.

 

Depreciation, Depletion, Amortization and Impairment.  For the three months ended June 30, 2014, depreciation, depletion, amortization, and impairment was $0.7 million, as compared to $1.7 million for the quarter ended June 30, 2013. The lower depletion is primarily a result of lower capitalized asset retirement costs as a result of a decrease to the asset retirement obligation and higher reserves in certain of our fields.

  

General and Administrative Expense.  General and administrative expense was $0.2 million for the three months ended June 30, 2014, as compared to $0.3 million for the three months ended June 30, 2013.  

 

Other Income (Expense).   Other expense was $0.2 million for the three months ended June 30, 2014, as compared to other expense of approximately $53,000 for the three months ended June 30, 2013. The difference is primarily attributable to an increase in loss on derivatives of approximately $190,000, partially offset by lower interest expense for the three months ended June 30, 2014.

 

 

Six Months Ended June 30, 2014 Compared to Six Months Ended June 30, 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 six months ended June 30, 2014 and 2013.

  

		Six Months Ended June 30,
		2014				2013
Revenue
Oil and Gas Sales (in thousands)		$	7,187			$	6,794
Net Production sold
Oil (Bbl)			66,670				63,628
Natural gas (Mcf)			144,307				145,992
Natural gas liquids (Bbl)			7,381				3,007
Total (Boe)			98,101				90,967
Total (Boe/d) (1)			542				503
Average sales prices
Oil ($/Bbl)		$	91.54			$	91.91
Natural gas ($/Mcf)			5.83				4.97
Natural gas liquids ($/Bbl)			32.92				29.91
Total average price ($/Boe)		$	73.26			$	79.49
Costs and expenses (per Boe)
Operating costs and marketing		$	9.66			$	14.72
Production taxes			5.87				4.27
Depreciation, depletion, amortization and impairment			19.17				30.72
Accretion of discount on asset retirement obligation			1.54				0.79
General and administrative expense			4.42				6.55

 

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

 

Six months Revenues and Sales Volumes

 

Oil and Natural Gas Sales Volumes.  During the six months ended June 30, 2014, we had total sales volumes of 98,101 Boe, compared to total sales volumes of 90,967 Boe during the six months ended June 30, 2013.  This increase is primarily attributable to production from new wells partially offset by natural declines in production.

 

Oil and Natural Gas Sales. During the six months ended June 30, 2014, we had oil and natural gas sales of $7.2 million, as compared to $6.8 million during the six months ended June 30, 2013, primarily as a result of production from new wells partially offset by natural declines in production.

 

Costs and Expenses  

 

Operating Costs.  During the six months ended June 30, 2014, we incurred operating costs of $0.9 million, as compared to $1.4 million during the six months ended June 30, 2013, primarily as a result of lower workover expenditures.  

 

Production Taxes.  Production taxes were $0.6 million for the six months ended June 30, 2014, as compared to $0.4 million for the six months ended June 30, 2013, primarily as a result of a different product mix.

 

Depreciation, Depletion, Amortization and Impairment.  For the six months ended June 30, 2014, depreciation, depletion, amortization, and impairment was $1.9 million, as compared to $2.8 million for the six months ended June 30, 2013. The lower depletion is primarily a result of lower capitalized asset retirement costs as a result of a decrease to the asset retirement obligation and higher reserves in certain of our fields.  

 

General and Administrative Expense.  General and administrative expense was $0.4 million for the six months ended June 30, 2014, as compared to $0.6 million for the six months ended June 30, 2013.  The decrease is primarily attributable to lower professional fees and rent expense.

 

Other Income (Expense).   Other expense was $0.4 million for the six months ended June 30, 2014, as compared to other income of $0.5 million for the six months ended June 30, 2013. The increase in other expense is primarily attributable to gain on settlement of debt of approximately $0.9 million for the six months ended June 30, 2013 with no corresponding gain during the six months ended June 30, 2014 and an increase in loss on derivatives of approximately $0.1 million, slightly offset by a decrease in interest expense.

 

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 months ended June 30, 2014, we had capital expenditures of approximately $1.4 million for the development of oil and natural gas properties. We anticipate capital expenditures of between $7 million and $10 million for the remainder of 2014. See “Planned Operations” for more information about our planned capital expenditures.

 

Liquidity

 

At June 30 2014, we had approximately $1.0 million in cash and cash equivalents and $9.2 million outstanding under our line of credit with Independent Bank.  At June 30, 2014, we had working capital deficit of approximately $1.7 million compared to a working capital deficit of approximately $1.3 million at June 30, 2013.

 

Cash Flows

 

Net cash provided by operating activities was $4.3 million for the six months ended June 30, 2014, compared to net cash provided by operating activities of $5.4 million for the six months ended June 30, 2013.  The decrease in net cash provided by operating activities was primarily due to a $2.7 million profit, $1.9 million of non-cash depletion and depreciation, and $0.6 million changes in working capital.

 

Net cash used in investing activities decreased to $1.4 million for the six months ended June 30, 2014 from $6.9 million for the six months ended June 30, 2013 due to fewer wells being drilled in the period ended June 30, 2014 as compared to the period ended June 30, 2013.

 

During the six months ended June 30, 2014, net cash used in financing was $2.7 million compared to net cash provided by financing of $1.3 million for the six months ended June 30, 2013, primarily related to borrowings on our line of credit during the six months ended June 30, 2013 compared to no borrowings during the six months ended June 30, 2014.

 

Indebtedness

 

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, as borrowers (the “Borrowers”) and Independent Bank, as Lender, providing for an up to $100,000,000 credit facility (the “Credit Facility”). RMR owns approximately 83% 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 its prior 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. Effective June 30, 2014, RMR assumed the Company’s obligations with respect to $3,000,000 of the Company’s outstanding borrowings under the Credit Facility in exchange for the satisfaction and discharge of a $2,900,000 intercompany payable from RMR to the Company.

 

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 June 30, 2014, the borrowers had borrowed a total of $26,800,000. As of June 30, 2014, the borrowing base was $30,000,000 million, leaving $3,200,000 of availability.

 

Off-Balance Sheet Arrangements

 

As of June 30, 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 June 30, 2014, we had $9.2 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 30, 2014). A hypothetical 10% change in the interest rates we pay on our borrowings under the Credit Facility as of June 30, 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 June 30, 2014.  Based on that evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective at the reasonable assurance level.

  

Changes in Internal Control Over Financial Reporting

 

During the quarter ended June 30, 2014, we engaged an accounting firm with significant public company internal control experience to identify improvements to each of our main business and accounting processes that affect the preparation of our financial statements. The accounting firm and management reviewed each business and accounting process and designed and implemented preventive and detective internal controls. We tested the new internal controls and deem them to be effective as of June 30, 2014.

 

 

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.

 

Item 6.

Exhibits

 

The exhibits required to be filed by this Item 6 are set forth in the Exhibit Index.

 

 

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.

  

		CROSS BORDERS RESOURCES, INC.
Dated: August 19, 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