Red Mountain Resources (RDMP) 8-K/A Financial Statements and Exhibits

Red Mountain Resources, Inc. 8-K/A

Exhibit 99.1

 

Cross Border Resources, Inc.

Balance Sheets

	December 31,		December 31,
	2013		2012
ASSETS
Current Assets
Cash and Cash Equivalents	$	726,239	$	241,561
Accounts Receivable – Oil and Natural Gas Sales		2,086,239		3,194,725
Accounts Receivable – Related Party		24,630		—
Prepaid Expenses & Other Current Assets		87,443		465,223
Derivative Asset - Current Portion		—		235,825
Current Tax Asset		19,600		21,737
Total Current Assets		2,944,151		4,159,071
Oil and Gas Properties		56,561,040		48,248,378
Less: Accumulated Depletion, Amortization, and Impairment		(20,941,867)		(16,018,892	)
Net Oil and Gas Properties		35,619,173		32,229,486
Other Assets
Other Property and Equipment, net of Accumulated Depreciation of $95,828 and $77,190  in 2013 and 2012, respectively		34,641		53,280
Restricted Cash		206,087		—
Deferred financing costs, net of accumulated amortization of $19,242 and $113,581 in 2013 and 2012, respectively		91,242		101,045
Derivative Asset, net of Current Portion		—		54,963
Other Assets		54,324		54,324
Total Other Assets		386,294		263,612
TOTAL ASSETS	$	38,949,618	$	36,652,169

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

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	December 31,			December 31,
	2013			2012
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts Payable - Trade	$	1,268,257		$	4,226,547
Accounts Payable – Related Party		—			215,495
Interest Payable		—			130,929
Accrued Expenses & Other Payables		63,101			61,065
Notes Payable Related Party - Current		—			764,278
Creditors Payable - Current Portion		—			758,167
Derivative Liability		38,109			—
Environmental Liability – Current Portion		1,400,000			860,000
Asset Retirement Obligation – Current Portion		562,000			452,013
Deferred Tax Liability		19,600			21,737
Total Current Liabilities		3,351,067			7,490,231
Non-Current Liabilities
Asset Retirement Obligations		2,952,898			2,865,345
Deferred Income Tax Liability		—			—
Environmental Liability, Net of Current Portion		687,973			1,240,000
Line of Credit		12,200,000			8,750,000
Creditors Payable, Net of Current Portion		—			594,616
Total Non-Current Liabilities		15,840,871			13,449,961
Total Liabilities		19,191,938			20,940,192
Commitments & Contingencies (Note 9)
Stockholders’ Equity
Common Stock ($0.001 par value; 99,000,000 shares authorized and 17,336,226 issued and outstanding as of December 31, 2013 and 16,301,946 as of December 31, 2012)		17,336			16,302
Additional Paid in Capital		33,462,473			32,770,540
Accumulated Deficit		(13,722,129	)		(17,074,865	)
Total Stockholders’ Equity		19,757,680			15,711,977
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	38,949,618		$	36,652,169

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

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 Cross Border Resources, Inc.

Statements of Operations

	Twelve Months Ended December 31,
	2013			2012
Revenues
Oil and gas sales	$	13,125,960		$	14,781,497
Expenses:
Operating costs		2,300,899			2,281,443
Environmental cleanup		—			2,100,000
Natural gas marketing and transportation expenses		78,211			143,672
Production taxes		1,246,153			1,171,474
Depreciation and depletion		4,941,614			5,671,202
Impairment of oil & gas properties		—			2,633,742
Loss on sale of oil and gas properties		—			—
Accretion expense		148,364			94,556
General and administrative		1,007,065			2,851,003
Total expense		9,722,306			16,947,092
Gain (loss) from operations		3,403,654			(2,165,595	)
Other income (expense):
Gain (loss) on derivatives		(269,769	)		575,086
Gain on settlement of debt		858,429			—
Bond issuance amortization		—			(218,631)
Interest expense		(639,578	)		(547,066	)
Miscellaneous other income (expense)		—			(3,089)
Total other income (expense)		(50,918	)		(193,700)
Income (loss) before income taxes		3,352,736			(2,359,295)
Current tax benefit		(—	)		(—)
Deferred tax expense		—			—
Income tax expense		—			(—)
Net income (loss)	$	3,352,736		$	(2,359,295)
Net income (loss) per share:
Basic	$	0.20		$	(0.15)
Diluted	$	0.16		$	(0.15)
Weighted average shares outstanding:
Basic		17,169,041			16,173,316
Diluted		20,856,541			16,173,316

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

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Cross Border Resources, Inc.

Statements of Cash Flows

	Twelve Months Ended December 31,
	2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	3,352,736		$	(2,359,295	)
Adjustments to reconcile net income (loss) to cash used by operating activities:
Depreciation, depletion, and impairment		4,941,614			8,304,944
Gain on Settlement of Creditors Liability		(350,800	)		—
Gain on Conversion of Notes		(485,416	)		—
Settlement of environmental liability		(12,027	)		—
Accretion of asset retirement obligations		148,364			94,556
(Gain) loss on disposition of assets					—
Amortization of and deferred financing costs		9,803			218,631
Change in derivative instruments		328,897			(375,782	)
Changes in operating assets and liabilities:
Accounts receivable		1,083,856			(2,010,181	)
Prepaid expenses and other current assets		375,666			1,343,721
Accounts payable		(2,245,392	)		112,713
Accounts payable – related party		—			—
Restricted Cash		(206,087	)		—
Accrued expenses		7,527			(413,746	)
Derivative asset/liability		—			—
Deferred income tax		—			—
Environmental liability		—			2,100,000
Deferred revenue		—			(32,479	)
Interest payable		—			18,270
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES		6,948,741			7,001,352
CASH FLOWS USED IN INVESTING ACTIVITIES
Capital expenditures - oil and gas properties		(9,253,152	)		(12,233,698	)
Proceeds from disposal of oil and gas properties		—			2,250,000
Capital expenditures - other assets		—			—
NET CASH USED IN INVESTING ACTIVITIES		(9,253,152	)		(9,983,698	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from issuance of common stock, net of expenses		—			—
Borrowings on line of credit		12,200,000			7,119,000
Payments on line of credit		(8,750,000	)		(750,000	)
Deferred financing costs		—			(36,299	)
Repayments of bonds		—			(3,395,000	)
Repayments to creditors		(660,911	)		(186,761	)
NET CASH PROVIDED BY FINANCING ACTIVITIES		2,789,089			2,750,940
NET DECREASE IN CASH AND CASH EQUIVALENTS		484,678			(231,406	)
Cash and cash equivalents, beginning of period		241,561			472,967
Cash and cash equivalents, end of period	$	726,239		$	241,561
Supplemental disclosures of cash flow information:
Interest paid	$	518,756		$	269,501
Income taxes paid	$	—		$	—
Issuance of common stock to settle liabilities	$	(692,967	)	$	—
Additions of ARO	$	51,290		$	383,481

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

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Cross Border Resources, Inc.

Statements of Equity

For the years ended December 31, 2013 and 2012

	Common Stock
	Shares	Amount	Additional Paid-in Capital		Accumulated Deficit			Total
Balance at December 31, 2011	16,151,946	16,152	32,617,690	$	(14,715,570	)	$	17,918,272
Issuance of shares to settle change of control liability with former CEO	150,000	150	152,850		—			153,000
Net loss attributable to shareholders	—	—	—		(2,359,295	)		(2,359,295	)
Balance at December 31, 2012	16,301,946	16,302	32,770,540		(17,074,865	)		15,711,977
Issuance of shares to Red Mountain Resources, Inc. upon conversion of unsecured liabilities	611,630	612	409,180		—			409,792
Issuance of shares to settle creditors payable claims	422,650	422	282,753		—			283,176
Net income attributable to shareholders	—	—	—		3,352,736			3,352,736
Balance at December 31, 2013	17,336,226	17,336	33,462,473		(13,722,129	)		19,757,681

5

 Cross Border Resources, Inc.

Notes to Financial Statements

1.  Organization

Nature of Operations

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

2.  Summary of Significant Accounting Policies

Reclassification

Certain amounts have been reclassified to conform to 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.

Concentrations of Credit Risk

All of our receivables are due from crude oil and natural gas purchasers. The Company sold approximately 78% of our crude oil and natural gas production to 5 customers during the year ended December 31, 2013. The Company believes that there are potential alternative purchasers and that it may be necessary to establish relationships with new purchasers. However, there can be no assurance that the Company can establish such relationships and that those relationships will result in an increased number of purchasers. Although the Company is exposed to credit risk, the Company believes that all of its purchasers are credit worthy. The Company had no bad debt for the years ended December 31, 2013 and 2012.

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 December 31, 2013 and December 31, 2012.

Oil and natural gas properties

The Company follows the successful efforts method of accounting for its oil and natural gas producing activities.  Costs to acquire mineral interests in oil and natural gas properties and to drill and equip development wells and related asset retirement costs are capitalized. Costs to drill exploratory wells are capitalized pending determination of whether the wells have proved reserves. If the Company determines that the wells do not have proved reserves, the costs are charged to expense. There were no exploratory wells capitalized pending determination of whether the wells have proved reserves at December 31, 2012 or 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 December 31, 2013, the Company had capitalized no interest costs because its exploration and development projects generally lasted less than six months. Costs incurred to maintain wells and related equipment are charged to expense as incurred.

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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 December 31, 2013 or December 31, 2012.

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Other property

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

Income taxes

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

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

Asset retirement obligations

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

Share-based compensation

The Company measures and records compensation expense for all share-based payment awards to employees and outside directors based on estimated grant date fair values. The Company recognizes compensation costs for awards granted over the requisite service period based on the grant date fair value.

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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 consolidated financial statements.

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

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3 – Asset retirement obligations

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

	December 31,			December 31,
	2013			2012
Asset retirement obligations at beginning of year	$	3,317,358		$	1,186,260
Disposal of assets		—			(88,650	)
Settlement of liabilities		(1,284	)		(55,915	)
Revision of previous estimates		—			1,797,626
Accretion expense		148,364			94,556
Additions		51,290			383,481
Asset retirement obligations at end of period	$	3,515,728		$	3,317,358
Less: current portion		562,000			452,013
Long-term portion	$	2,952,898		$	2,865,345

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:

	December 31,			December 31,
	2013			2012
Oil and natural gas properties	$	56,561,040		$	48,248,378
Less accumulated depletion and impairment		(20,941,867	)		(16,018,892	)
Net oil and natural gas properties capitalized costs	$	35,619,173		$	32,229,486

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

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

Other property and equipment

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

	December 31,			December 31,
	2013			2012
Other property and equipment	$	130,470		$	130,470
Less accumulated depreciation		(95,828	)		(77,190	)
Net property and equipment	$	34,641		$	53,280

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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 3,125,000 shares of the Company’s common stock at a per share price of $2.25 (the "$2.25 Warrants").  The Company also issued warrants to purchase 3,600,000 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 1.92 years, respectively. The Company does not expect the immediate exercise of these warrants as the exercise price exceeds the average closing market price for the Company's common stock. Furthermore, no assurances can be made that any of the warrants will ever be exercised for cash or at all.

Issuance of Shares to Former Executive

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

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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 years ended December 31 2013 and December 31, 2012, 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 at December 31, 2011	87,500	$	4.80	5.08
Granted	—		—	—
Cancelled	—		—	—
Exercised	—		—	—
Forfeited	—		—	—
Expired	—		—	—
Outstanding and exercisable at 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

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 our 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. (“Red Mountain”), issued approximately 750,000 shares of its common stock to the creditors in settlement of the claims.  In return for Red Mountain issuing its shares to the creditors payable, the Company issued Red Mountain 422,650 shares of its common stock.

Conversion of Notes Payable

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

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6 – Related party transactions

During the year ended December 31, 2012, Red Mountain incurred approximately $628,274 for general and administrative expenses and operating costs that will be reimbursed by the Company for accounting services and attendance of certain of the Company’s directors and officers at the Company’s annual meeting of stockholders and for costs associated with workovers on three of the Company’s salt water disposal wells, of which $215,495 remained unpaid at December 31, 2012.  The expenditures pertaining to the operating costs were incurred pursuant to a technical services agreement between the Company and Red Mountain.

During the year ended December 31, 2013, Red Mountain incurred approximately $3,000,000 of such expenditures, all of which was repaid at December 31, 2013.

7 – Long term debt

Notes Payable Green Shoe Investments – Related Party

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

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

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

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

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

13

Notes Payable Little Bay Consulting – Related Party

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

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

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

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

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

Line of Credit – Texas Capital Bank

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

As of December 31, 2013 and December 31, 2012, the outstanding balance on the TCB line of credit was $0 and $8,750,000, respectively.

Credit Facility

On February 5, 2013, the Company entered into the Credit Agreement with Red Mountain, Black Rock Capital, Inc. and RMR Operating, LLC (the Company, Red Mountain, Black Rock Capital, Inc. and RMR Operating, LLC, jointly and severally, the “Borrowers”) and Independent Bank, as Lender. The Credit Agreement provides for an up to $100.0 million revolving credit facility (as amended, the “Credit Facility”) with an initial commitment of $20.0 million and a maturity date of February 5, 2016.  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. Effective September 12, 2013, the borrowing base was increased to $30.0 million from $20.0 million. As of December 31, 2013, the borrowing base and commitment were $30.0 million. As of December 31, 2013, the Company had $12.2 million outstanding under the Credit Facility and had availability of $15.2 million.

14

On, January 21, 2014, March 13, 2014 and March 20, 2014, Red Mountain, withdrew $5.0 million, $1.0 million, and $3.0 million, respectively, under the Credit Facility with Independent Bank. As of April 15, 2014, the Company had availability of $6.2 million under the Credit Facility.

Amounts outstanding under the Credit Facility bear interest 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%. Interest is payable monthly in arrears on the last day of each calendar month. As of December 31, 2013, the interest rate was 4%. Borrowings under the Credit Facility are secured by first priority liens on substantially all the property of each of the Borrowers and are unconditionally guaranteed by Doral West Corp. and Pure Energy Operating, Inc., each a subsidiary of Cross Border.

The Credit Agreement also contains financial covenants, measured as of the last day of each fiscal quarter of the Company. As of December 31, 2013, the Company was in compliance with these covenants.

Pursuant to the Credit Agreement, at least one of the Borrowers is required to have acceptable hedge agreements in place at all times effectively hedging at least 50% of the oil volumes of the Borrowers. Pursuant to the terms of the Credit Agreement, the Company has hedge agreements with BP Energy hedging a portion of the future oil production of the Borrowers.

8 – Creditors payable

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

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

9 – Commitments and contingencies

Litigation

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

15

The Company was previously party to an engagement letter, dated February 7, 2012 (the "Engagement Letter"), with KeyBanc Capital Markets Inc. ("KeyBanc") pursuant to which KeyBanc was to act as exclusive financial advisor to the Company’s Board of Directors in connection with a possible "Transaction" (as defined in the Engagement Letter).  The Engagement Letter was formally terminated by the Company on August 21, 2012. The Engagement Letter provided that KeyBanc would be entitled to a fee upon consummation of a Transaction within a certain period of time following termination of the Engagement Letter. On May 16, 2013, KeyBanc delivered an invoice to the Company in the amount of $751,334, representing amounts purportedly owed by the Company to KeyBanc as a result of the consummation of a purported Transaction KeyBanc asserts had been consummated within the required time period and its out-of-pocket expenses in connection therewith.  The Company disputes that any Transaction was consummated and that KeyBanc is entitled to any out-of-pocket expenses.  The matter was originally filed 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 Key Banc filed a counter claim against the Company. The Company and Key Banc have each filed motions for summary judgement, requesting the Court to rule in their respective Favors. The Company intends to vigorously defend the action.

Environmental Contingencies

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

As of December 31, 2013, the Company had $2,087,973 in environmental liabilities related to its operated Tom Tom Tomahawk field 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 these expenditures over a eighteen month period beginning in January 2014.

10 – 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 December 31, 2013, the Company had a net derivative liability of $38,109, as compared to a net derivative asset of $290,788 at December 31, 2012.  The change in net derivative asset/liability is recorded as non-cash mark-to-market income or loss.  Mark-to-market losses of $283,831 were recorded in the twelve months ended December 31, 2013 as compared to mark-to-market income of $330,716 during the twelve months ended December 31, 2012.  Net realized hedge settlement gain for the twelve months ended December 31, 2013 was $14,062 as compared to $244,370 for the twelve months ended December 31, 2012.  The combination of these two components of derivative expense/income is reflected in "Other Income (Expense)" on the Statements of Operations as "Gain (loss) on derivatives."

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As of December 31, 2013, the Company had crude oil swaps in place relating to a total of 3,000 Bbls per month, as follows:

				Price	Volumes	Fair Value of Outstanding Derivative Contracts(1) as of
Transaction				Per	Per		December 31,		December
Date	Type(2)	Beginning	Ending	Unit	Month		2013		31, 2012
March 2011	Swap	04/01/2011	02/28/2013	$104.55	1,000	$	—	$	41,019
November 2011	Swap	12/01/2011	11/30/2014	$93.50	2,000		(62,730)		44,942
February 2012	Swap	03/01/2012	02/28/2014	$106.50	1,000		24,621		204,827
						$	(38,109)	$	290,788

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

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

11 – 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 December 31, 2013 and December 31, 2012:

	Fair Value Measurements at Reporting Date Using
	Quoted Prices in Active Markets for Identical Assets or Liabilities  (Level 1)		Significant or Other Observable Inputs (Level 2)				Significant Unobservable Inputs (Level 3)				Fair Value at December 31, 2013
Assets:
Commodities derivatives	$	—		$	3,504			$	—			$	3,504
Total	$	—		$	3,504			$	—			$	3,504
Liabilities
Environmental liability	$	—		$	—			$	(2,086,833	)		$	(2,086,833	)
Asset retirement obligations (non-recurring)	$	—		$	—			$	(3,514,898	)		$	(3,514,898	)
Commodities Derivative	$	—		$	(38,109	)		$	—			$	(38,109
Total	$	—		$	(38,109	)		$	(5,601,731	)		$	(5,639,840	)

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	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, 2012
Assets:
Commodities derivatives	$	—	$	290,788	$	—		$	290,788
Total	$	—	$	290,788	$	—		$	290,788
Liabilities:
Environmental liability	$	—	$	—	$	(2,100,000	)	$	(2,100,000	)
Asset retirement obligations (non-recurring)		—		—		(3,317,358	)		(3,317,358	)
Total	$	—	$	—	$	(5,417,358	)	$	(5,417,358	)

The following is a summary of changes to fair value measurements using Level 3 inputs during the 12 months ended December 31, 2013:

	Environmental Liability
Balance, December 31, 2012	$	2,100,000
Acquisitions		—
Settlement of liabilities		11,657
Revisions of previous estimates		—
Balance, December 31, 2013	$	2,087,973

12 – Income taxes

Total income tax expense (benefit) differed from the amounts computed by applying the U.S. Federal statutory tax rates to pre-tax income:

	Year Ended December 31,
(in thousands)	2013			2012
Income taxes at U.S. statutory rate		1,140			(802	)
State taxes, net of federal impact		88			(63	)
Change in valuation allowance		(1,229	)		864
Permanent differences		1			1
Other differences		0			0
Total		0			0

Deferred tax assets/(liabilities) consist of the following:

	Year Ended December 31,
(in thousands)	2013			2012
Derivatives		(34	)		105
Valuation allowance		(5,972	)		(7,200	)
Difference in depreciation and capitalization methods-natural gas properties,		(3,444	)		(379	)
Accrued expenses		765			769
Net operating losses		8,685			6,705
Total		0			0

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Deferred tax assets and liabilities are the result of temporary differences between the financial statement carrying values and tax bases of assets and liabilities. The Company’s net deferred tax assets and liabilities are recorded as a long-term liability of $0 at December 31, 2013 and 2012, respectively.

As of December 31, 2013, the Company had net operating loss carryfowards (“NOLs”) of approximately $23.7 million which will begin to expire, if unused, in 2026.

The Company continually assesses both positive and negative evidence to determine whether it is more likely than not that deferred tax assets can be realized prior to their expiration.  Management monitors Company-specific, oil and natural gas industry and worldwide economic factors and assesses the likelihood that the Company's NOLs and other deferred tax attributes in the United States, state, and local tax jurisdictions will be utilized prior to their expiration.  The Company establishes a valuation allowance 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. At December 31, 2013, and 2012 the Company had a valuation allowance of $6.0 million and $7.2 million, respectively, related to its deferred tax assets.

The company recognizes the financial statement effects of tax positions when it is more likely than not, based on the technical merits, that the position will be sustained upon examination by a taxing authority. Recognized tax positions are initially and subsequently measured as the largest amount of tax benefit that is more likely than not of being realized upon ultimate settlement with a taxing authority. We have not taken a tax position that, if challenged, would have a material effect on the financial statements or the effective tax rate for the periods ended December 31, 2013 and December 31, 2012. There were no interest and penalties related to unrecognized tax positions for the periods ended December 31, 2013 and December 31, 2012. The tax years subject to examination by tax jurisdictions in the United States are 2009 through 2012.

13 - Supplemental information relating to oil and natural gas producing activities (unaudited)

Costs incurred in oil and natural gas property acquisition, exploration and development

Set forth below is certain information regarding the costs incurred for oil and gas property acquisition, development and exploration activities:

	Year Ended December 31,
	2013		2012
Property acquisition costs:
Unproved properties	$	—	$	—
Proved properties		—		—
Exploration costs		—		—
Development costs (1)		8,312,662		13,261,812
Total costs incurred	$	8,312,662	$	13,261,812

(1) For the years ended December 31, 2013 and 2012, development costs included $51,290 and $383,481, respectively, in non-cash, asset retirement obligations.

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Results of operations for oil and natural gas producing activities

Set forth below is certain information regarding the results of operations for oil and gas producing activities:

	Year Ended December 31,
	2013		2012
Revenues	$	13,125,960	$	14,781,497
Production costs		2,300,899		2,281,443
Impairment		—		2,663,742
Depletion		4,941,614		5,671,202
Income tax expense		—		—
Accretion expense		148,364		94,556
Gain on sale of properties		—		—
Environmental cleanup		—		2,100,000
Natural gas marketing		78,211		143,672
Production taxes		1,246,153		1,171,471
Results of operations	$	4,410,719	$	685,408

Proved reserves

       Cawley, Gillespie and Associates, Inc, independent petroleum engineers estimated 100% of the proved reserve information for the Company properties as of December 31, 2013.

Joe C. Neal & Associates, Inc., independent petroleum engineers estimated 100% of the proved reserve information for the Company properties as of December 31, 2012. Each year’s estimate of proved reserves and related valuations were also prepared in accordance with then-current provisions of ASC 932,Extractive Activities.

Estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes and other factors. All of the Company’s estimated oil and natural gas reserves are attributable to properties within the United States. A summary of the Company’s changes in quantities of proved oil and natural gas reserves for the years ended December 31, 2013 and 2012 are as follows:

	Oil (MBbls)			Natural Gas (MMcf)			Total (MBoe)
December 31, 2011		1,708			2,385			2,106
Acquisitions		(144	)		(143	)		(168	)
Extensions and discoveries		16			265			210
Revisions in previous estimates		(308	)		(518	)		(394	)
Production		(151	)		(294	)		(200	)
December 31, 2012		1,271			1,695			1,554
Acquisitions		—			—			—
Extensions and discoveries		371			817			507
Revisions of previous estimates		11			906			161
Production		(123	)		(283	)		(170	)
December 31, 2013		1,530			3,135			2,052
Proved Developed Reserves
December 31, 2012		804			1,336			1,027
December 31, 2013		804			2,215			1,173
Proved Undeveloped Reserves
December 31, 2012		467			359			527
December 31, 2013		726			920			879

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Standardized measure of discounted future net cash flows relating to proved reserves

Future cash inflows were computed by applying the average on the closing price on the first day of each month for the 12-month period prior to December 31, 2013 to estimated future production. Future production and development costs are computed by estimating the expenditures to be incurred in developing and producing the proved oil and natural gas reserves at year end, based on year-end costs and assuming continuation of existing economic conditions.

Future income tax expenses are calculated by applying appropriate year-end tax rates to future pre-tax net cash flows relating to proved oil and natural gas reserves, less the tax basis of properties involved.

Future income tax expenses give effect to permanent differences, tax credits and loss carryforwards relating to the proved oil and natural gas reserves. Future net cash flows are discounted at a rate of 10% annually to derive the standardized measure of discounted future net cash flows. This calculation procedure does not necessarily result in an estimate of the fair market value of the Company’s oil and natural gas properties.

The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows:

	Year Ended December 31,
	2013		2012
Future cash inflows	$	153,544,250	$	120,208,031
Future production costs		(41,381,543 )		(47,186,808	)
Future development costs		(18,821,422)		(22,620,478	)
Future income tax expense		(20,243,102)		(12,218,429	)
Future net cash flows		73,098,179		38,182,316
10% annual discount for estimated timing of cash flows		(36,817,148)		(19,542,639	)
Standardized measure of discounted future net cash flows	$	36,281,031	$	18,639,677

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Changes in standardized measure of discounted future net cash flows

The changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows:

	Year Ended December 31,
	2013		2012
Balance, beginning of period	$	28,147,572	$	44,862,000
Net change in sales and transfer prices and in production (lifting) costs related to future production		9,374,986		(18,916,722	)
Changes in estimated future development costs		4,042,730		11,934,249
Sales and transfers of oil and natural gas produced during the period		(10,825,061)		(11,227,504	)
Net change due to extensions and discoveries		12,107,955		(3,726,923	)
Net change due to revisions in quantity estimates		3,883,464		6,992,767
Previously estimated development costs incurred during the period		(8,312,662)		(16,602,246	)
Accretion of discount		2,747,142		4,486,195 465,035
Other		(672,750)		9,880,721
Net change in income taxes		(4,212,345)		—
Balance, end of period	$	36,281,031	$	28,147,572

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