Manufactured Housing Properties (MHPC) 10-K 25 Mar 14 2013 FY Annual report Financial data

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
	Dec. 31, 2013	Mar. 25, 2014	Jun. 30, 2013
Document And Entity Information	'	'	'
Entity Registrant Name	'Caprock Oil, Inc.	'	'
Entity Central Index Key	'0001277998	'	'
Document Type	'10-K	'	'
Document Period End Date	31-Dec-13	'	'
Amendment Flag	'false	'	'
Current Fiscal Year End Date	'--12-31	'	'
Is Entity a Well-known Seasoned Issuer?	'No	'	'
Is Entity a Voluntary Filer?	'No	'	'
Is Entity's Reporting Status Current?	'Yes	'	'
Entity Filer Category	'Smaller Reporting Company	'	'
Entity Public Float	'	'	$42,600
Entity Common Stock, Shares Outstanding	'	51,088,276	'
Document Fiscal Period Focus	'FY	'	'
Document Fiscal Year Focus	'2013	'	'

Consolidated_Balance_Sheets

Consolidated Balance Sheets (USD $)	Dec. 31, 2013	Dec. 31, 2012
Assets	'	'
Cash and cash equivalents	$875,540	$512,835
Accounts receivable (less allowance for doubtful accounts of $228,574 at December 31, 2013 and 2012)	286,893	333,601
Prepaid expenses and other	54,252	77,315
Notes receivable from sale of subsidiary	0	778,596
Total current assets	1,216,685	1,702,347
Oil and gas properties, evaluated (full cost method)	14,939,989	14,928,690
Other property and equipment	40,978	187,568
Total Property and equipment	14,980,967	15,116,258
Less: Accumulated depreciation, depletion & amortization	-9,934,526	-9,597,881
Net property and equipment	5,046,441	5,518,377
Notes receivable from sale of subsidiary (less allowance for uncollectible amount of $250,000 at December 31, 2012)	0	632,306
Other noncurrent assets	5,238	5,238
Total other assets	5,238	637,544
Total assets	6,268,364	7,858,268
Liabilities and Stockholders' Equity	'	'
Current portion of long-term debt - stockholders	0	14,714
Current portion of long-term debt - third parties	1,875,032	2,558,790
Accounts payable	549,896	723,513
Accrued liabilities	1,488,981	1,613,474
Fair value of oil and gas derivatives	0	4,900
Total current liabilities	3,913,909	4,915,391
Long-term debt, net of current portion	0	194,324
Deferred income taxes	1,300,500	508,800
Asset retirement obligations	435,840	398,710
Total liabilities	5,650,249	6,017,225
Stockholders' equity:	'	'
Preferred stock, $.01 par value per share, 1,000,000 shares authorized, None issued	0	0
Common stock, $.01 par value per share, 200,000,000 shares authorized, 2,655,738 shares issued and outstanding	26,557	26,557
Additional paid in capital	13,160,302	12,894,490
Accumulated deficit	-12,568,744	-11,080,004
Total stockholders' equity	618,115	1,841,043
Total liabilities and stockholders' equity	$6,268,364	$7,858,268

Consolidated_Balance_Sheets_Pa

Consolidated Balance Sheets (Parenthetical) (USD $)	Dec. 31, 2013	Dec. 31, 2012
Stockholders' equity:	'	'
Preferred stock, par value	$0.01	$0.01
Preferred stock, authorized shares	1,000,000	1,000,000
Preferred stock, Issued shares	0	0
Common stock, par value	$0.01	$0.01
Common stock, authorized shares	200,000,000	5,000,000
Common stock, issued shares	2,655,738	2,655,738
Common stock, outstanding shares	2,655,738	2,655,738

Consolidated_Statements_of_Ope

Consolidated Statements of Operations (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Revenues:	'	'
Oil and gas sales	$2,623,071	$2,839,579
Total revenues	2,623,071	2,839,579
Operating expenses:	'	'
Lease operating expense	1,330,848	1,549,693
Depreciation, depletion & amortization	413,887	490,629
Accretion expense	37,130	33,970
Workover expense	292,876	779,269
Selling, general and administrative	883,455	1,018,747
Total operating expenses	2,958,196	3,872,308
Operating loss	-335,125	-1,032,729
Other income (expense):	'	'
Interest income	50,129	126,105
Interest expense	-130,709	-163,161
Loss on settlement of notes receivable	-286,235	-250,000
Gain on oil and gas derivatives	4,900	150,540
Loss before income taxes	-697,040	-1,169,245
(Provision) benefit for income taxes	-791,700	398,200
Net loss	($1,488,740)	($771,045)
Net loss per share, basic and diluted	($0.56)	($0.29)
Weighted average shares outstanding, basic and diluted	2,655,738	2,655,738

Consolidated_Statements_of_Sto

Consolidated Statements of Stockholders' Equity (USD $)	Common Stock	Additional Paid-In Capital	Accumulated Deficit	Total
Beginning Balance - Amount at Dec. 31, 2011	$26,557	$12,894,490	($10,308,959)	$2,612,088
Beginning Balance - Shares at Dec. 31, 2011	2,655,738	'	'	'
Net loss	'	'	-771,045	-771,045
Ending Balance, Amount at Dec. 31, 2012	26,557	12,894,490	-11,080,004	1,841,043
Ending Balance, Shares at Dec. 31, 2012	2,655,738	'	'	'
Related Party Interest Forgiveness	'	265,812	'	265,812
Net loss	'	'	-1,488,740	-1,488,740
Ending Balance, Amount at Dec. 31, 2013	$26,557	$13,160,302	($12,568,744)	$618,115
Ending Balance, Shares at Dec. 31, 2013	2,655,738	'	'	'

Consolidated_Statements_of_Cas

Consolidated Statements of Cash Flows (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Cash flows from operating activities:	'	'
Net loss	($1,488,740)	($771,045)
Depreciation, depletion & amortization	413,887	490,629
Provision (benefit) for income taxes	791,700	-398,200
Loss on settlement of notes receivable	286,235	250,000
Unrealized gain on oil and gas derivatives	-4,900	-150,540
Accretion expense	37,130	33,970
Changes in current assets and liabilities	52,812	309,170
Other changes, net	2,516	-5,238
Net cash flows from operating activties	90,640	-241,254
Cash flows from investing activities:	'	'
Collection of notes receivable from sale of subsidiary	950,000	819,172
Purchase of property and equipment	-11,299	-108,548
Sale of property and equipment	11,657	0
Net cash flows from investing activities	950,358	710,624
Cash flows from financing activities:	'	'
Payments of long term debt	-663,579	-479,699
Proceeds from long term debt	0	69,510
Net payments of stockholder advances	-14,714	-305,286
Net cash flows from financing activities	-678,293	-715,475
Net increase (decrease) in cash and cash equivalents	362,705	-246,105
Cash and cash equivalents at beginning of period	512,835	758,940
Cash and cash equivalents at end of period	875,540	512,835
Supplemental cash flow data:	'	'
Cash paid for interest	119,933	156,676
Supplemental non-cash financing/investing activity:	'	'
Forgiveness of related party interest expense	265,812	0
Notes payable assumed in settlement agreement	216,305	0
Notes payable assumed for sale of property and equipment	57,690	0
Notes payable issued for insurance financing	51,096	0
Note payable issued for purchase of property and equipment	$0	$29,334

1_Business_and_Summary_of_Sign

1. Business and Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2013
Stockholders notes and advances	'
1. Business and Summary of Significant Accounting Policies	'
	Description of Business – Caprock Oil, Inc. (“we”, “our” or the "Company") is a Nevada corporation, whose operations are presently focused on the Exploration & Production business. In that business, our wholly-owned subsidiaries, CYMRI, L.L.C. (“CYMRI”) and Triumph Energy, Inc. (“Triumph”), maintain working interests in various producing oil and gas properties in Texas and Louisiana.
	The Company underwent a “change of control” at the shareholder level in September 2013.  As a result of that transaction, the U.S. tax operating loss carryforwards that the Company previously reported became subject to certain annual limitations on their availability to offset future taxable income (see Note 6).
	Principles of Consolidation – The consolidated financial statements include the accounts of Caprock Oil, Inc. and its wholly-owned subsidiaries, CYMRI and Triumph.  All significant intercompany amounts are eliminated in consolidation.  Certain reclassifications have been made to the prior year statements to conform to the current year presentation.
	Cash Equivalents – For purposes of the statement of cash flows, the Company considers all highly liquid debt instruments with original maturities of three months or less to be cash equivalents.
	Oil and Gas Operations – For its oil and gas operations, the Company follows the sales method for recognizing its revenues and the full cost method in accounting for its costs.  Costs associated with acquisition, exploration, and development of oil and gas reserves, including directly related overhead costs, are capitalized.  (a) Capitalized costs of oil and gas properties, including the estimated future costs to develop proved reserves, are amortized on the unit-of-production method using estimates of proved reserves.  Investments in unproved properties and major development projects are not amortized until proved reserves associated with the projects can be determined or until impairment occurs.  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; (b) The capitalized costs are subject to a “ceiling test,” which basically limits such costs to the aggregate of the “estimated present value,” discounted at a 10-percent interest rate, of future net revenues from proved reserves, based on current economic and operating conditions, plus the lower of cost or fair market value of unproved properties; and (c) Sales of proved and unproved properties are accounted for as adjustments of capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and gas, in which case the gain or loss is recognized in income.
	Asset Retirement Obligations and Environmental Costs - The Company records the fair value of legal obligations to retire and remove long-lived assets in the period in which the obligation is incurred (typically when the asset is installed at the production location).  When the liability is initially recorded, the cost is capitalized by increasing the carrying amount of the related properties, plant and equipment.  Over time the liability is increased for the change in its present value, and the capitalized cost in properties, plant and equipment is depreciated over the useful life of the related asset.  Environmental expenditures are expensed or capitalized, depending upon their future economic benefit.  Expenditures that relate to an existing condition caused by past operations, and do not have a future economic benefit, are expensed.
	Other Property and Equipment – Other property and equipment, primarily office furniture and fixtures, is depreciated on a straight-line basis over their useful lives ranging from three to five years.
	Allowance for Doubtful Accounts – The Company has provided an allowance for uncollectible accounts receivable based on management's evaluation of collectability of outstanding balances. The allowance is based on estimates and actual losses may vary from current estimates.
	Income Taxes – Income taxes are accounted for under the asset and liability method (see Note 6).  Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using statutory tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities from a change in tax rates is recognized in income in the period that includes the effective date of the change.
	We follow ASC 740, “Income Taxes.”  ASC 740 creates a single model to address accounting for the uncertainty in income tax positions and prescribes a minimum recognition threshold a tax position must meet before recognition in the financial statements.  We apply significant judgment in evaluating our tax positions and estimating our provision for income taxes.  The actual outcome of these future tax consequences could differ significantly from these estimates, which could impact our financial position, results of operations and cash flows.  The evaluation of a tax position in accordance with ASC 740 is a two-step process.  The first step is a recognition process to determine whether it is more likely than not that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes.  The second step is a measurement process whereby a tax position that meets the more likely than not recognition threshold is calculated to determine the amount of  benefit/expense to recognize in the financial statements.  The tax position is measured at the largest amount of benefit/expense that is more likely than not of being realized upon ultimate settlement.  No liability for unrecognized tax benefits was recorded as of December 31, 2013 or 2012.
	Net Income (Loss) Per Share – Basic income (loss) per common share is computed by dividing the net income or loss by the weighted average number of shares of Common Stock outstanding during the period.  Diluted income per common share is computed by considering dilutive common share equivalents under the Treasury Stock method.  For the years ended December 31, 2013 and 2012, the basic and diluted average outstanding shares are the same because inclusion of common share equivalents would be anti-dilutive.
	Use of Estimates – Management has made a number of estimates and assumptions in preparing these financial statements in conformity with accounting principles generally accepted in the United States of America.  Actual results could differ from those estimates.
	Recently Issued Accounting Pronouncements – In July 2013, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2013-11, “Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists.” This update provides guidance on when an unrecognized tax benefit should be presented in the financial statements as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss, or a tax credit carryforward.  This update is effective for fiscal years beginning after December 15, 2013.  The adoption of this update, effective January 1, 2014, is not expected to have a material impact on the Company’s financial statements.
	In February 2013, the FASB issued ASU No. 2013-02, “Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income.” This update addresses the reporting of certain reclassifications out of accumulated other comprehensive income on the respective line items in the income statement, depending on whether such amounts are required to be reclassified in their entirety to net income.  The adoption of ASU 2013-02, effective January 1, 2013, has not had a material impact on the Company’s financial statements.
	In January 2013, the FASB issued ASU 2013-01, “Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities.”  This update clarifies the asset/liability offsetting requirements in a previous update, with respect to derivatives and certain other types of debt and security agreements.  The adoption of ASU 2013-01, effective January 1, 2013, has not had a material impact on the Company’s financial statements.
	In 2013 and early 2014, the FASB issued several additional Accounting Standards Updates which do not have applicability to the Company.

2_Sale_of_Canadian_Energy_Serv

2. Sale of Canadian Energy Services Business	12 Months Ended
	Dec. 31, 2012
Sale Of Canadian Energy Services Business	'
2. Sale of Canadian Energy Services Business	'
	On June 3, 2011, the Company entered into a Stock Purchase Agreement (“SPA”) with a private company to sell the capital stock of its Canadian Energy Services subsidiaries, Decca Consulting, Ltd. and Decca Consulting, Inc. (collectively referred to as “Decca”), for a total sales price of $4,600,000 (plus a working capital adjustment).  The sales price consisted of the following components: (a) Cash amount of $350,000 paid at closing; (b) Non-interest bearing notes (the “Receivables Notes”) issued by the purchaser in the amount of $2,776,274 (including the working capital adjustment of $376,274), payable out of the post-closing collection of Decca’s accounts receivable; and (c) Interest bearing notes (the “Installment Notes”) issued by the purchaser in the amount of $1,850,000, payable in 48 monthly installments of principal and interest, at 8% per annum, commencing on October 1, 2011. The Company recognized a pre-tax gain from this sale in the year ended December 31, 2011 in the amount of $2,695,100.
	Beginning in June 2011 and continuing through March 2012, the purchaser made periodic payments to the Company on the Receivables Notes in the aggregate amount of $2,776,274, resulting in such notes being fully paid at that time.  With regard to the Installment Notes in the aggregate amount of $1,850,000, the purchaser did not make monthly payments on the notes beginning in October 2011, in accordance with the stated terms.  In April 2012, the Company and the purchaser reached an informal agreement whereby the purchaser began making the stated monthly note payments under a delayed payment plan.  Such monthly payments continued through December 2012, at which time, the purchaser informed the Company that it would defer making further monthly payments on the Installment Notes, pending resolution of certain indemnity provisions in the SPA.  At that time, the outstanding balance of principal and accrued interest on the Installment Notes was $1,660,902.
	In February 2013, the dispute between the parties regarding the Installment Notes was referred to binding arbitration as permitted under the SPA.  In June 2013, the Company and the purchaser reached a preliminary agreement to settle the outstanding balance of the Installment Notes effectively terminating the arbitration proceedings.  The terms of the settlement agreement provided for the purchaser to make a one-time cash payment to the Company and to assume all of the Company’s remaining obligations, including any continent liabilities, related to its prior ownership of Decca.  The Company’s acceptance of the preliminary settlement on the Installment Notes resulted in a total pre-tax net loss in the amount of $536,235.  The Company had previously recognized an estimated loss provision in the fourth quarter of 2012 in the amount of $250,000, therefore, an additional loss provision was recognized in the second quarter of 2013 in the amount of $286,235.  The definitive settlement was closed and funded with the purchaser in December 2013.  In this closing, the Company did not receive the full amount of cash originally anticipated from the purchaser in the preliminary settlement, however, such cash shortfall was contractually reimbursed in a payment to the Company from an escrow account arising from the “change of control” transaction in September 2013 (see Note 1), therefore, there was no adjustment made to the previously booked loss provision.

3_Going_Concern

3. Going Concern	12 Months Ended
	Dec. 31, 2013
Going Concern	'
3. Going Concern	'
	The accompanying consolidated financial statements have been prepared on a going concern basis, which contemplates the realization of assets and satisfaction of liabilities in the normal course of business. The Company has reported net losses from continuing operations in the last two years and has a substantial working capital deficit as of December 31, 2013.  These factors, among others, indicate that the Company may be unable to continue as a going concern for a reasonable period of time. The consolidated financial statements do not contain any adjustments to reflect the possible future effects on the classification of assets or the amounts and classification of liabilities that may result should the Company be unable to continue as a going concern.

4_Commodity_Derivatives

4. Commodity Derivatives	12 Months Ended
	Dec. 31, 2013
CommodityDerivativesAbstract	'
4. Commodity Derivatives	'
	Through December 31, 2013, the Company had a commodity derivative contract with a major energy company covering a portion of a subsidiary’s domestic oil production.  This contract consisted of a two year “costless collar,” with floor and ceiling prices of $80.00 and $108.00 per barrel, and expired on December 31, 2013. For the periods of any open derivative contracts, the Company applies “mark to market” accounting in accordance with ASC 815-20, “Accounting for Derivative Instruments and Hedging Activities,” and accounts for such contracts as non-hedging transactions, as defined in ASC 815-20.  Accordingly, we reflect changes in fair value of open derivative contracts in current period earnings, based on “Level 3” inputs.  In the years ended December 31, 2013 and 2012, we reported unrealized derivative gains of $4,900 and $150,540, respectively, due to fair value changes (see Note 9).  In the years ended December 31, 2013 and 2012, we reported no realized derivative gains or losses.

5_Long_Term_Debt

5. Long Term Debt	12 Months Ended
	Dec. 31, 2013
Long-term Debt, Unclassified [Abstract]	'
5. Long Term Debt	'
	As of December 31, 2013 and 2012, the Company had the following long-term debt obligations:
		December 31,
		2013			2012
	$25,000,000 line of credit with a bank, maturing on January 1, 2015, interest at 1.0% above prime (but not less than 5.5%) payable monthly, secured by first lien on CYMRI, LLC’s oil and gas properties, with a declining borrowing base of $1,836,000 as of December 31, 2013	$	1,836,000		$	2,436,000
	Notes payable to 2 individuals, incurred in acquisition of Decca Consulting, Ltd., paid and restructured into newly issued notes payable in 48 monthly installments of principal and interest (at 8% per annum) commencing October 1, 2011, in conjunction with sale of Decca (see Note 2)		-			216,305
	Advances from stockholders, bearing interest at 10%, unsecured (extended since March 2010)		-			14,714
	Other short term notes for automobile and insurance financing, interest rates at 6% to 8%		39,032			100,809
			1,875,032			2,767,828
	Current portion of long term debt - stockholders		-			(14,714	)
	Current portion of long term debt - third parties		(1,875,032	)		(2,558,790	)
	Long term debt, net of current portions	$	-		$	194,324
	Future maturities of long-term debt as of December 31, 2013 are as follows:
	Year ending December 31, 2014	$	1,875,032
	Year ending December 31, 2015		-
	Year ending December 31, 2016		-
	Year ending December 31, 2017		-
	Year ending December 31, 2018		-
		$	1,875,032
	Borrowings under the bank credit agreement secured by the oil and gas properties owned by CYMRI, LLC (“CYMRI”), a subsidiary in the Exploration & Production business, are subject to a borrowing base, which is periodically redetermined based on oil and gas reserves.  The bank credit agreement generally does not require monthly principal payments so long as outstanding borrowings are less than a declining borrowing base.  As of December 31, 2013, there was no unutilized borrowing base under the bank credit agreement.
	Effective January 1, 2014, the bank credit agreement was amended to redefine the borrowing base as declining by $50,000 per month while substantially retaining all other significant terms and extending the maturity for 12 months to January 1, 2015.  As the extended debt amount is essentially due within one year after December 31, 2013, the outstanding borrowings are classified as a current liability as of December 31, 2013.

6_Income_Taxes

6. Income Taxes	12 Months Ended
	Dec. 31, 2013
Notes to Financial Statements	'
6. Income Taxes	'
	The Company provided the following amounts of current and deferred income tax provision (benefit) for the years ended December 31, 2013 and 2012:
		Year ended December 31,
		2013			2012
	Current income taxes	$	-		$	-
	Deferred income taxes		791,700			(398,200	)
	Total income tax provision (benefit)	$	791,700		$	(398,200	)
	The following table shows components of income tax provision (benefit) in comparison to the U.S. statutory tax rate of 34% for the years ended December 31, 2013 and 2012:
		Year ended December 31,
		2013			2012
	Tax benefit at U.S. statutory rate	$	(236,994	)	$	(397,543	)
	Non-deductible items		1,792			(657	)
	Operating loss carryforward adjustment		936,502			-
	Gain on forgiveness of interest expense (see Note 7)		90,400			-
	Total income tax provision (benefit)	$	791,700		$	(398,200	)
	The following table indicates the tax effects of temporary differences giving rise to our deferred tax assets and liabilities as of December 31, 2013 and 2012:
		December 31,
		2013			2012
	Deferred tax assets:
	Operating loss carryforwards	$	229,800		$	1,095,300
	Other, net		58,900			60,700
	Gross deferred tax assets		288,700			1,156,000
	Deferred tax liabilities:
	Property and equipment		(1,589,200	)		(1,664,800	)
	Other, net		-			-
	Gross deferred tax liabilities		(1,589,200	)		(1,664,800	)
	Net deferred tax liabilities	$	(1,300,500	)	$	(508,800	)
	As of December 31, 2012, we had consolidated U.S. tax operating loss carryforwards of approximately $3,222,000, expiring in future years.  As a result of a “change of control” transaction in September 2013, such tax operating loss carryforwards became subject to certain annual limitations which have severely restricted their availability to offset our future taxable income (see Note 1).  Accordingly, we have recognized an adjustment in the year ended December 31, 2013 to reduce the carrying value of the deferred tax asset associated with our tax operating loss carryforwards to $229,800.  Due to this adjustment, we reported a tax provision in the year ended December 31, 2013 in the amount of $791,700, notwithstanding the fact that we reported a pre-tax net loss for that period.

7_Related_Party_Transactions

7. Related Party Transactions	12 Months Ended
	Dec. 31, 2013
Notes to Financial Statements	'
7. Related Party Transactions	'
	The Company repaid unsecured stockholder advances in the amounts of $14,714 and $305,286 in the years ended December 31, 2013 and 2012, respectively, resulting in no further amounts remaining outstanding (see Note 5).  The Company had previously accrued interest on such obligations at a rate of 10% per annum.  As a precedent to the “change of control” transaction described in Note 1, the Company determined that past unpaid accruals of interest expense on former stockholder advances were no longer required, accordingly, a gain on forgiveness of interest expense in the amount of $265,812 was credited to Additional paid-in capital in the year ended December 31, 2013 (there was an income tax provision of $90,400 related to this gain).  As of December 31, 2012, the Company had granted a second lien on its oil and gas properties to a former stockholder in the amount of approximately $1,300,000, however, the second lien was released on July 30, 2013.

8_Commitments_and_Contingencie

8. Commitments and Contingencies	12 Months Ended
	Dec. 31, 2013
Notes to Financial Statements	'
8. Commitments and Contingencies	'
	The Company and its subsidiaries have operating leases for office space under which rental expense amounted to approximately $70,000 and $65,000 in the years ended December 31, 2013 and 2012, respectively.  As of December 31, 2013, aggregate commitments under the Company’s operating leases were as follows:
	Year ending December 31, 2014	$	67,000
	Year ending December 31, 2015		60,000
	Year ending December 31, 2016		61,000
	Year ending December 31, 2017		41,000
	Year ending December 31, 2018		-
		$	229,000
	From time to time the Company may become involved in litigation in the ordinary course of business. At the present time, other than the Company’s disclosures below, the Company’s management is not aware of any such litigation that could have a material adverse effect on its results of operations, cash flows or financial condition.
	Triumph Energy, Inc., a subsidiary in the Exploration & Production segment, and a former subsidiary which was sold in 2008, have been named as joint defendants in several lawsuits involving professional liability and other matters arising in the normal course of business in the State of Louisiana.  Most of these cases have been settled with little or no net cost to Triumph.  It is not practical at the present time to determine the amount or likelihood of an unfavorable outcome to the Company’s consolidated financial position or results of operations of any of the remaining actions against Triumph.  The Company believes that Triumph has meritorious defenses in each case and is vigorously defending these matters.  The Company has recorded no provision for estimated losses in these cases as of December 31, 2013.
	In October 2008, an insurer for the Company’s inactive Construction Staffing subsidiary filed a lawsuit against the subsidiary alleging default on a premium finance obligation in the amount of approximately $200,000, plus interest and attorney’s fees.  The Company believes that its inactive Construction Staffing subsidiary has a meritorious position in this matter and has not engaged legal counsel to defend this case.  A default judgment was rendered in favor of the plaintiff in January 2011 and the Company has recorded an accrual for the subsidiary’s estimated loss exposure of approximately $100,000 as of December 31, 2013.
	The Company, as a lessee and operator of oil and gas properties, is subject to various federal, state and local laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on the lessee under an oil and gas lease for the cost of pollution clean-up resulting from operations and subject the lessee to liability for pollution damages. The Company maintains insurance coverage, which it believes is customary in the industry, although the Company is not fully insured against all environmental risks. The Company is not aware of any environmental claims existing as of December 31, 2013, which have not been provided for, covered by insurance or otherwise have a material impact on its financial position or results of operations. There can be no assurance, however, that current regulatory requirements will not change, or past noncompliance with environmental laws will not be discovered on the Company’s properties.

9_Other_Required_Disclosures

9. Other Required Disclosures	12 Months Ended
	Dec. 31, 2013
Notes to Financial Statements	'
9. Other Required Disclosures	'
	Asset Retirement Obligations – The Company records an asset retirement obligation (“ARO”) when the total depth of a drilled well is reached and the Company can reasonably estimate the fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon costs. The Company records the ARO liability on the consolidated balance sheets and capitalizes a portion of the cost in oil and gas properties equal to the estimated future cost to satisfy the abandonment obligation using current prices that are escalated by an assumed inflation factor up to the estimated settlement date and adjusted for the Company’s credit risk. This amount is discounted to present value using an assumed cost of funds for the Company.  After recording these amounts, the ARO is accreted to its future estimated value using the same assumed cost of funds.  The Company did not drill or abandon any properties in the years ended December 31, 2013 and 2012.  Therefore, the only ARO transactions were to accrue accretion expense of $37,130 and $33,970, respectively, in the years ended December 31, 2013 and 2012.
	Credit Risk Concentrations – As previously noted, the Company’s remaining operations are in the domestic Exploration & Production segment.  In that segment, the Company sells produced oil and gas mostly to well-known commodity purchasers from whom it does not require collateral.  In the years ended December 31, 2013 and 2012, there was one major customer, Gulfmark Energy, which represented 85% and 83%, respectively, of the Company’s consolidated revenues.  There were no other customers representing more than 10% of the Company’s consolidated revenues in the years ended December 31, 2013 and 2012.
	The Company maintains its domestic cash accounts in three different federally chartered banking institutions.  Its bank accounts in each bank are government insured up to $250,000 with the Company’s book balance at one bank exceeding that level by approximately $617,000 as of December 31, 2013.
	Fair Value of Financial Instruments – ASC 820, “Fair Value Measurements,” establishes a framework for measuring fair value and expands disclosures about fair value measurements.  This Statement applies under other accounting pronouncements that require or permit fair value measurements.  Disclosures about fair value of financial instruments are based on pertinent information available to management and are not necessarily indicative of the amounts that could be realized on disposition of the financial instruments.
	The statement requires disclosure that establishes a framework for measuring fair value and expands disclosure about fair value measurements. It requires fair value measurements be classified and disclosed in one of the following categories: (1) Level 1 - Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. We consider active markets as those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis.  (2)  Level 2  -  Quoted prices in markets that are not active or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that we value using observable market data. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument, can be derived from observable data or supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include non-exchange traded derivatives such as over-the-counter commodity price swaps, investments and interest rate swaps. (3) Level 3  -  Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources (i.e. supported by little or no market activity).  Our valuation models are primarily industry-standard models that consider various inputs including: (a) quoted forward prices for commodities, (b) time value, (c) volatility factors and (d) current market and contractual prices for the underlying instruments, as well as other relevant information.  Pursuant to ASC 820, we valued our commodity derivatives contract based on a “Level 3” input which consisted of a valuation model provided by the counterparty (see Note 4).
	Management has estimated the fair values of cash, accounts receivable, accounts payable and accrued liabilities (including oil and gas revenues received on behalf of unlocatable revenue interest owners) to approximate their respective carrying values reported on these financial statements because of their relatively short maturities. The carrying amounts of notes receivable and notes payable approximate fair value because their interest rates approximate market for items of similar risk.

10_Oil_and_Gas_Producing_Activ

10. Oil and Gas Producing Activities (Unaudited)	12 Months Ended
	Dec. 31, 2013
Notes to Financial Statements	'
10. Oil and Gas Producing Activities (Unaudited)	'
	Capitalized Costs of Oil and Gas Properties – The Company has owned working interests in oil and gas properties since acquiring CYMRI in May 2006.  The table below reflects the capitalized costs of such oil and gas properties as of December 31, 2013 and 2012 (in thousands):
		December 31,
		2013			2012
	Proved oil and gas properties	$	14,940		$	14,928
	Unproved oil and gas properties		-			-
	Gross oil and gas properties		14,940			14,928
	Less: Accumulated depreciation, depletion & amortization		(9,880	)		(9,466	)
	Net oil and gas properties	$	5,060		$	5,462
	Costs Incurred in Oil and Gas Producing Activities – The table below presents the costs incurred in oil and gas producing activities for the years ended December 31, 2013 and 2012 (in thousands):
		December 31,
		2013			2012
	Property acquisition	$	-		$	-
	Exploration		-			-
	Development		11			109
	Total costs incurred	$	11		$	109
	Results of Operations for Oil and Gas Producing Activities – The table below presents the results of operations for oil and gas producing activities for the years ended December 31, 2013 and 2012 (in thousands):
		Year ended December 31,
		2013			2012
	Revenues	$	2,623		$	2,840
	Production costs		(1,624	)		(2,329	)
	Depreciation, depletion & amortization		(414	)		(491	)
	Impairment expense		-			-
	Income taxes		(199	)		(7	)
	Results of operations	$	386		$	13
	Oil and Gas Reserves – The following table sets forth summary information with respect to CYMRI/Triumph’s proved oil and gas reserves as of December 31, 2013, prepared by the Company’s independent reservoir engineering firm. The estimates of proved and proved developed reserve quantities and the related measure of discounted future net cash flows are estimates only and do not purport to reflect realizable values or fair market values of the Company’s reserves.  The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise and generally more conservative than those of producing oil and gas properties.  Accordingly, these estimates are expected to change as future information becomes available.  All of the Company's reserves are located in the United States.
		Oil			Gas			Total			PV10 Value
		(MBbl)			(MMcf)			(MMcfe)			(000's)
	Proved developed reserves		396			678			3,055		$	10,069
	Proved undeveloped reserves		-			-			-			-
	Total proved reserves		396			678			3,055			10,069
	Discounted future income taxes											(3,303	)
	Standarized measure of discounted future net cash flows										$	6,766
	Proved reserves are estimated reserves of crude oil (including condensate and natural gas liquids) and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.  Proved developed reserves are those expected to be recovered through existing wells, equipment, and operating methods.
	The following table sets forth changes in the Company’s proved oil and gas reserves in the years ended December 31, 2013 and 2012 (in thousands):
		Oil			Gas			Total
		(MBbl)			(MMcf)			(MMcfe)
	Balance at January 1, 2012		472			771			3,603
	Revisions of previous estimates		32			(30	)		161
	Production		(27	)		(78	)		(240	)
	Balance at December 31, 2012		477			663			3,524
	Revisions of previous estimates		(56	)		79			(255	)
	Production		(25	)		(64	)		(214	)
	Balance at December 31, 2013		396			678			3,055
	The standardized measure of discounted future net cash flows is computed by applying estimated prices of oil and gas (at 2013 first of the month average monthly prices) to the estimated future production of proved oil and gas reserves, less estimated future expenditures (at year-end 2013 costs) to be incurred in developing and producing the proved reserves, and assuming continuation of existing economic conditions. The estimated future net cash flows are then discounted using a rate of 10-percent per year to reflect the estimated timing of the future net cash flows.  The Company does not believe that the standardized measure of discounted future net cash flows is necessarily indicative of the fair value of its oil and gas properties.  The following table sets forth the components of the standardized measure of discounted future net cash flows relating to proved oil and gas reserves as of December 31, 2013 and 2012 (in thousands):
		December 31,
		2013			2012
	Future net revenues	$	40,681		$	48,846
	Future lease operating expenses and production taxes		(21,284	)		(22,563	)
	Future development costs		(140	)		(1,568	)
	Future income taxes		(6,318	)		(7,225	)
	Future net cash flows		12,939			17,490
	10% annual discount for estimated timing of cash flows		(6,173	)		(9,156	)
	Standardized measure of discounted future net cash flows	$	6,766		$	8,334
	The following table sets forth changes in the standardized measure of the Company’s discounted future cash flows (“FCF”) relating to its proved oil and gas reserves in the years ended December 31, 2013 and 2012 (in thousands):
		Year ended December 31,
		2013			2012
	Net changes in prices and production costs	$	(1,077	)	$	305
	Sales and transfers of oil and gas produced		(1,292	)		(1,290	)
	Net change due to revisions in quantity estimates		(603	)		395
	Future development costs		673			(11	)
	Net change in income taxes		136			477
	Changes in production rates, other		(238	)		(1,272	)
	Accretion of discount		833			885
Changes in standardized measure of discounted FCF		(1,568	)		(511	)
Beginning standardized measure of discounted FCF		8,334			8,845
Ending standardized measure of discounted FCF	$	6,766		$	8,334
In accordance with the guidelines of the SEC, the reservoir engineers’ estimates of future net revenues from our properties and the pre-tax PV 10 Value amounts thereof are made using oil and gas sales prices in effect as of the dates of such estimates and are held constant throughout the life of the properties, except where such guidelines permit alternate treatment, including the use of fixed and determinable contractual price escalations. The average beginning of the month prices for the year ended December 31, 2013 used in such estimates were $96.84 per barrel of oil and $3.41 per Mcf of gas.

11_Subsequent_Events

11. Subsequent Events	12 Months Ended
	Dec. 31, 2013
Subsequent Events [Abstract]	'
11. Subsequent Events	'
	Effective March 17, 2014, the Company completed the acquisition of Cinco NRG, LLC (“Cinco”), a private oil and gas company, which was under common control by our majority shareholder.  The Company acquired Cinco through the issuance of a total of 46,942,538 shares of its Common Stock.  As a result of this transaction, the members of Cinco, including our majority shareholder, now own approximately 95% of our total shares of Common Stock outstanding (we also increased our total authorized shares of Common Stock to 200,000,000 shares).  In conjunction with this transaction, the Company issued 1,250,000 shares of its Common Stock to an officer of the Company and also amended its stock option plan.  Cinco was formed in April 2013 to acquire working interests in specific oil and gas properties in the States of Texas and Alabama.  At present, Cinco has a 10% non-operated working interest in a currently producing field in Texas and a 50% operated working interest in two exploratory prospects in Alabama.  Cinco is now a wholly-owned subsidiary of the Company.
	In the first quarter of 2014, the Company incurred a substantial expense for the unanticipated workover of CYMRI’s largest producing oil and gas well, which typically accounts for approximately 25% of our total oil and gas revenues.  The cost of the workover operation on this well was approximately $350,000.  Additionally, during the period of the workover operation, CYMRI received no oil and gas revenues from this well for more than two months.

1_Business_and_Summary_of_Sign1

1. Business and Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2013
Business And Summary Of Significant Accounting Policies Policies	'
Description of Business	'
	Description of Business – Caprock Oil, Inc. (“we”, “our” or the "Company") is a Nevada corporation, whose operations are presently focused on the Exploration & Production business. In that business, our wholly-owned subsidiaries, CYMRI, L.L.C. (“CYMRI”) and Triumph Energy, Inc. (“Triumph”), maintain working interests in various producing oil and gas properties in Texas and Louisiana.
	The Company underwent a “change of control” at the shareholder level in September 2013.  As a result of that transaction, the U.S. tax operating loss carryforwards that the Company previously reported became subject to certain annual limitations on their availability to offset future taxable income (see Note 6).
Principles of Consolidation	'
	Principles of Consolidation – The consolidated financial statements include the accounts of Caprock Oil, Inc. and its wholly-owned subsidiaries, CYMRI and Triumph.  All significant intercompany amounts are eliminated in consolidation.  Certain reclassifications have been made to the prior year statements to conform to the current year presentation.
Cash Equivalents	'
	Cash Equivalents – For purposes of the statement of cash flows, the Company considers all highly liquid debt instruments with original maturities of three months or less to be cash equivalents.
Oil and Gas Operations	'
	Oil and Gas Operations – For its oil and gas operations, the Company follows the sales method for recognizing its revenues and the full cost method in accounting for its costs.  Costs associated with acquisition, exploration, and development of oil and gas reserves, including directly related overhead costs, are capitalized.  (a) Capitalized costs of oil and gas properties, including the estimated future costs to develop proved reserves, are amortized on the unit-of-production method using estimates of proved reserves.  Investments in unproved properties and major development projects are not amortized until proved reserves associated with the projects can be determined or until impairment occurs.  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; (b) The capitalized costs are subject to a “ceiling test,” which basically limits such costs to the aggregate of the “estimated present value,” discounted at a 10-percent interest rate, of future net revenues from proved reserves, based on current economic and operating conditions, plus the lower of cost or fair market value of unproved properties; and (c) Sales of proved and unproved properties are accounted for as adjustments of capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and gas, in which case the gain or loss is recognized in income.
Asset Retirement Obligations and Environmental Costs	'
	Asset Retirement Obligations and Environmental Costs - The Company records the fair value of legal obligations to retire and remove long-lived assets in the period in which the obligation is incurred (typically when the asset is installed at the production location).  When the liability is initially recorded, the cost is capitalized by increasing the carrying amount of the related properties, plant and equipment.  Over time the liability is increased for the change in its present value, and the capitalized cost in properties, plant and equipment is depreciated over the useful life of the related asset.  Environmental expenditures are expensed or capitalized, depending upon their future economic benefit.  Expenditures that relate to an existing condition caused by past operations, and do not have a future economic benefit, are expensed.
Other Property and Equipment	'
	Other Property and Equipment – Other property and equipment, primarily office furniture and fixtures, is depreciated on a straight-line basis over their useful lives ranging from three to five years.
Allowance for Doubtful Accounts	'
	Allowance for Doubtful Accounts – The Company has provided an allowance for uncollectible accounts receivable based on management's evaluation of collectability of outstanding balances. The allowance is based on estimates and actual losses may vary from current estimates.
Income Taxes	'
	Income Taxes – Income taxes are accounted for under the asset and liability method (see Note 6).  Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using statutory tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities from a change in tax rates is recognized in income in the period that includes the effective date of the change.
	We follow ASC 740, “Income Taxes.”  ASC 740 creates a single model to address accounting for the uncertainty in income tax positions and prescribes a minimum recognition threshold a tax position must meet before recognition in the financial statements.  We apply significant judgment in evaluating our tax positions and estimating our provision for income taxes.  The actual outcome of these future tax consequences could differ significantly from these estimates, which could impact our financial position, results of operations and cash flows.  The evaluation of a tax position in accordance with ASC 740 is a two-step process.  The first step is a recognition process to determine whether it is more likely than not that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes.  The second step is a measurement process whereby a tax position that meets the more likely than not recognition threshold is calculated to determine the amount of  benefit/expense to recognize in the financial statements.  The tax position is measured at the largest amount of benefit/expense that is more likely than not of being realized upon ultimate settlement.  No liability for unrecognized tax benefits was recorded as of December 31, 2013 or 2012.
Net Income (Loss) Per Share	'
	Net Income (Loss) Per Share – Basic income (loss) per common share is computed by dividing the net income or loss by the weighted average number of shares of Common Stock outstanding during the period.  Diluted income per common share is computed by considering dilutive common share equivalents under the Treasury Stock method.  For the years ended December 31, 2013 and 2012, the basic and diluted average outstanding shares are the same because inclusion of common share equivalents would be anti-dilutive.
Use of Estimates	'
	Use of Estimates – Management has made a number of estimates and assumptions in preparing these financial statements in conformity with accounting principles generally accepted in the United States of America.  Actual results could differ from those estimates.
Recently Issued Accounting Pronouncements	'
	Recently Issued Accounting Pronouncements – In July 2013, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2013-11, “Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists.” This update provides guidance on when an unrecognized tax benefit should be presented in the financial statements as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss, or a tax credit carryforward.  This update is effective for fiscal years beginning after December 15, 2013.  The adoption of this update, effective January 1, 2014, is not expected to have a material impact on the Company’s financial statements.
	In February 2013, the FASB issued ASU No. 2013-02, “Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income.” This update addresses the reporting of certain reclassifications out of accumulated other comprehensive income on the respective line items in the income statement, depending on whether such amounts are required to be reclassified in their entirety to net income.  The adoption of ASU 2013-02, effective January 1, 2013, has not had a material impact on the Company’s financial statements.
	In January 2013, the FASB issued ASU 2013-01, “Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities.”  This update clarifies the asset/liability offsetting requirements in a previous update, with respect to derivatives and certain other types of debt and security agreements.  The adoption of ASU 2013-01, effective January 1, 2013, has not had a material impact on the Company’s financial statements.
	In 2013 and early 2014, the FASB issued several additional Accounting Standards Updates which do not have applicability to the Company.

5_Long_Term_Debt_Tables

5. Long Term Debt (Tables)	12 Months Ended
	Dec. 31, 2013
Notes to Financial Statements	'
Long Term Debt	'
		December 31,
		2013			2012
	$25,000,000 line of credit with a bank, maturing on January 1, 2015, interest at 1.0% above prime (but not less than 5.5%) payable monthly, secured by first lien on CYMRI, LLC’s oil and gas properties, with a declining borrowing base of $1,836,000 as of December 31, 2013	$	1,836,000		$	2,436,000
	Notes payable to 2 individuals, incurred in acquisition of Decca Consulting, Ltd., paid and restructured into newly issued notes payable in 48 monthly installments of principal and interest (at 8% per annum) commencing October 1, 2011, in conjunction with sale of Decca (see Note 2)		-			216,305
	Advances from stockholders, bearing interest at 10%, unsecured (extended since March 2010)		-			14,714
	Other short term notes for automobile and insurance financing, interest rates at 6% to 8%		39,032			100,809
			1,875,032			2,767,828
	Current portion of long term debt - stockholders		-			(14,714	)
	Current portion of long term debt - third parties		(1,875,032	)		(2,558,790	)
	Long term debt, net of current portions	$	-		$	194,324
Future maturities of long-term debt	'
	Year ending December 31, 2014	$	1,875,032
	Year ending December 31, 2015		-
	Year ending December 31, 2016		-
	Year ending December 31, 2017		-
	Year ending December 31, 2018		-
		$	1,875,032

6_Income_Taxes_Tables

6. Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2013
Income Taxes Tables	'
Income tax benefit from continuing operations	'
		Year ended December 31,
		2013			2012
	Current income taxes	$	-		$	-
	Deferred income taxes		791,700			(398,200	)
	Total income tax provision (benefit)	$	791,700		$	(398,200	)
Schedule of Effective Income Tax Rate Reconciliation	'
		Year ended December 31,
		2013			2012
	Tax benefit at U.S. statutory rate	$	(236,994	)	$	(397,543	)
	Non-deductible items		1,792			(657	)
	Operating loss carryforward adjustment		936,502			-
	Gain on forgiveness of interest expense (see Note 7)		90,400			-
	Total income tax provision (benefit)	$	791,700		$	(398,200	)
Deferred tax assets and liabilities	'
		December 31,
		2013			2012
	Deferred tax assets:
	Operating loss carryforwards	$	229,800		$	1,095,300
	Other, net		58,900			60,700
	Gross deferred tax assets		288,700			1,156,000
	Deferred tax liabilities:
	Property and equipment		(1,589,200	)		(1,664,800	)
	Other, net		-			-
	Gross deferred tax liabilities		(1,589,200	)		(1,664,800	)
	Net deferred tax liabilities	$	(1,300,500	)	$	(508,800	)

8_Commitments_and_Contingencie1

8. Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2013
Commitments And Contingencies Tables	'
Operating leases commitments	'
	Year ending December 31, 2014	$	67,000
	Year ending December 31, 2015		60,000
	Year ending December 31, 2016		61,000
	Year ending December 31, 2017		41,000
	Year ending December 31, 2018		-
		$	229,000

10_Oil_and_Gas_Producing_Activ1

10. Oil and Gas Producing Activities (Tables)	12 Months Ended
	Dec. 31, 2013
Oil And Gas Producing Activities Tables	'
Capitalized Costs of Oil and Gas Properties	'
		December 31,
		2013			2012
	Proved oil and gas properties	$	14,940		$	14,928
	Unproved oil and gas properties		-			-
	Gross oil and gas properties		14,940			14,928
	Less: Accumulated depreciation, depletion & amortization		(9,880	)		(9,466	)
	Net oil and gas properties	$	5,060		$	5,462
Costs Incurred in Oil and Gas Producing Activities	'
		December 31,
		2013			2012
	Property acquisition	$	-		$	-
	Exploration		-			-
	Development		11			109
	Total costs incurred	$	11		$	109
Results of Operations for Oil and Gas Producing Activities	'
		Year ended December 31,
		2013			2012
	Revenues	$	2,623		$	2,840
	Production costs		(1,624	)		(2,329	)
	Depreciation, depletion & amortization		(414	)		(491	)
	Impairment expense		-			-
	Income taxes		(199	)		(7	)
	Results of operations	$	386		$	13
Oil and Gas Reserves	'
		Oil			Gas			Total			PV10 Value
		(MBbl)			(MMcf)			(MMcfe)			(000's)
	Proved developed reserves		396			678			3,055		$	10,069
	Proved undeveloped reserves		-			-			-			-
	Total proved reserves		396			678			3,055			10,069
	Discounted future income taxes											(3,303	)
	Standarized measure of discounted future net cash flows										$	6,766
Proved oil and gas reserves	'
		Oil			Gas			Total
		(MBbl)			(MMcf)			(MMcfe)
	Balance at January 1, 2012		472			771			3,603
	Revisions of previous estimates		32			(30	)		161
	Production		(27	)		(78	)		(240	)
	Balance at December 31, 2012		477			663			3,524
	Revisions of previous estimates		(56	)		79			(255	)
	Production		(25	)		(64	)		(214	)
	Balance at December 31, 2013		396			678			3,055
Discounted future net cash flows relating to proved oil and gas reserves	'
		December 31,
		2013			2012
	Future net revenues	$	40,681		$	48,846
	Future lease operating expenses and production taxes		(21,284	)		(22,563	)
	Future development costs		(140	)		(1,568	)
	Future income taxes		(6,318	)		(7,225	)
	Future net cash flows		12,939			17,490
	10% annual discount for estimated timing of cash flows		(6,173	)		(9,156	)
	Standardized measure of discounted future net cash flows	$	6,766		$	8,334
Discounted future cash flows ("FCF") relating to its proved oil and gas reserves	'
		Year ended December 31,
		2013			2012
	Net changes in prices and production costs	$	(1,077	)	$	305
	Sales and transfers of oil and gas produced		(1,292	)		(1,290	)
	Net change due to revisions in quantity estimates		(603	)		395
	Future development costs		673			(11	)
	Net change in income taxes		136			477
	Changes in production rates, other		(238	)		(1,272	)
	Accretion of discount		833			885
	Changes in standardized measure of discounted FCF		(1,568	)		(511	)
	Beginning standardized measure of discounted FCF		8,334			8,845
	Ending standardized measure of discounted FCF	$	6,766		$	8,334

2_Sale_of_Canadian_Energy_Serv1

2. Sale of Canadian Energy Services Business (Details Narrative) (USD $)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2013	Dec. 31, 2012
Sale Of Canadian Energy Services Business Details Narrative	'	'	'
Pre-tax gain	$2,695,100	'	'
Outstanding balance of principal and accrued interest on the Installment Notes	'	'	1,660,902
Current Asset	'	$0	$778,596

4_Commodity_Derivatives_Detail

4. Commodity Derivatives (Details Narrative) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Commodity Derivatives Details Narrative	'	'
Unrealized derivative gains	$4,900	$150,540

5_Long_Term_Debt_Details

5. Long Term Debt (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
Notes to Financial Statements	'	'
$25,000,000 line of credit with a bank, maturing on January 1, 2015, interest at 1.0% above prime (but not less than 5.5%) payable monthly, secured by first lien on CYMRI, LLC's oil and gas properties, with a declining borrowing base of $1,836,000 as of December 31, 2013	$1,836,000	$2,436,000
Notes payable to 2 individuals, incurred in acquisition of Decca Consulting, Ltd., paid and restructured into newly issued notes payable in 48 monthly installments of principal and interest (at 8% per annum) commencing October 1, 2011, in conjunction with sale of Decca (see Note 2)	0	216,305
Advances from stockholder, bearing interest at 10%, unsecured (extended since March 2010)	0	14,714
Other short term notes for automobile and insurance financing, interest rates at 6% to 8%	39,032	100,809
Total Long Term Debt Obligations	1,875,032	2,767,828
Current portion of long term debt - stockholders	0	-14,714
Current portion of long term debt - third parties	-1,875,032	-2,558,790
Long term debt, net of current portions	$0	$194,324

5_LongTerm_Debt_Details_1

5. Long-Term Debt (Details 1) (USD $)	Dec. 31, 2013
Long-Term Debt Details 1	'
Year ending December 31, 2014	$1,875,032
Year ending December 31, 2015	0
Year ending December 31, 2016	0
Year ending December 31, 2017	0
Year ending December 31, 2018	0
Total	$1,875,032

6_Income_Taxes_Details

6. Income Taxes (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Income Taxes Details	'	'
Current income taxes	$0	$0
Deferred income taxes	791,700	-398,200
Total	$791,700	($398,200)

6_Income_Taxes_Details_1

6. Income Taxes (Details 1) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Income Taxes Details 1	'	'
Tax benefit at U.S. statutory rate	($236,994)	($397,543)
Non-deductible items	1,792	-657
Operating loss carryforward adjustment	936,502	0
Gain on forgiveness of interest expense (see Note 7)	90,400	0
Total income tax provision (benefit)	$791,700	($398,200)

6_Income_Taxes_Details_2

6. Income Taxes (Details 2) (USD $)	Dec. 31, 2013	Dec. 31, 2012
Deferred tax assets:	'	'
Operating loss carryforwards	$229,800	$1,095,300
Other, net	58,900	60,700
Gross deferred tax assets	288,700	1,156,000
Deferred tax liabilities:	'	'
Property and equipment	-1,589,200	-1,664,800
Other, net	0	0
Gross deferred tax liabilities	-1,589,200	-1,664,800
Net deferred tax liabilities	($1,300,500)	($508,800)

6_Income_Taxes_Details_Narrati

6. Income Taxes (Details Narrative) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Income Tax Disclosure [Abstract]	'	'
U.S. statutory tax rate	34.00%	34.00%
U.S. tax operating loss carryforwards	'	$3,222,000

7_Related_Party_Transactions_D

7. Related Party Transactions (Details Narrative) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Related Party Transactions Details Narrative	'	'
Stockholders notes and advances	$14,714	$305,286
Forgiveness of related party interest expense	$265,812	$0

8_Commitments_and_Contingencie2

8. Commitments and Contingencies (Details) (USD $)	Dec. 31, 2013
Commitments And Contingencies Details	'
Year ending December 31, 2014	$67,000
Year ending December 31, 2015	60,000
Year ending December 31, 2016	61,000
Year ending December 31, 2017	41,000
Year ending December 31, 2018	0
Operating lease, Net	$229,000

8_Commitments_and_Contingencie3

8. Commitments and Contingencies (Details Narrative) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Commitments And Contingencies Details Narrative	'	'
Contingency loss	$100,000	'
Rental expense	$70,000	$65,000

9_Other_Required_Disclosures_D

9. Other Required Disclosures (Details Narrative) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Accretion expense	$37,130	$33,970
Consolidated revenues from continuing operations percentage of Gulfmark Energy	85.00%	83.00%
Amount exceeds the level of insured amount	617,000	'
Maximum [Member]	'	'
Government insured amount	$250,000	'

10_Oil_and_Gas_Producing_Activ2

10. Oil and Gas Producing Activities (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Capitalized Costs of Oil and Gas Properties	'	'
Proved oil and gas properties	$14,940	$14,928
Unproved oil and gas properties	0	0
Gross oil and gas properties	14,940	14,928
Less: Accumulated depreciation, depletion & amortization	-9,880	-9,466
Net oil and gas properties	$5,060	$5,462

10_Oil_and_Gas_Producing_Activ3

10. Oil and Gas Producing Activities (Details 1) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Costs Incurred in Oil and Gas Producing Activities	'	'
Property acquisition	$0	$0
Exploration	0	0
Development	11	109
Total costs incurred	$11	$109

10_Oil_and_Gas_Producing_Activ4

10. Oil and Gas Producing Activities (Details 2) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Results of Operations for Oil and Gas Producing Activities	'	'
Revenues	$2,623	$2,840
Production costs	-1,624	-2,329
Depreciation, depletion & amortization	-414	-491
Impairment expense	0	0
Income taxes	-199	-7
Results of operations	$386	$13

10_Oil_and_Gas_Producing_Activ5

10. Oil and Gas Producing Activities (Details 3) (USD $)	Dec. 31, 2013
In Thousands, unless otherwise specified
Oil and Gas Reserves	'
Proved developed reserves	$10,069
Proved undeveloped reserves	0
Total proved reserves	10,069
Discounted future income taxes	-3,303
Standarized measure of discounted future net cash flows	$6,766
Oil	'
Oil and Gas Reserves	'
Proved developed reserves	'396
Proved undeveloped reserves	'0
Total proved reserves	'396
Gas	'
Oil and Gas Reserves	'
Proved developed reserves	'678
Proved undeveloped reserves	'0
Total proved reserves	'678
Total	'
Oil and Gas Reserves	'
Proved developed reserves	'3055
Proved undeveloped reserves	'0
Total proved reserves	'3055

10_Oil_and_Gas_Producing_Activ6

10. Oil and Gas Producing Activities (Details 4)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Oil	'	'	'
Begining Balance	'	'	'472
Revisions of previous estimates	'(56)	'32	'
Production	'(25)	'(27)	'
Ending Balance	'396	'477	'
Gas	'	'	'
Begining Balance	'	'	'771
Revisions of previous estimates	'79	'(30)	'
Production	'(64)	'(78)	'
Ending Balance	'678	'663	'
Total	'	'	'
Begining Balance	'	'	'3603
Revisions of previous estimates	'(255)	'161	'
Production	'(214)	'(240)	'
Ending Balance	'3055	'3524	'

10_Oil_and_Gas_Producing_Activ7

10. Oil and Gas Producing Activities (Details 5) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Oil And Gas Producing Activities Details 5	'	'
Future net revenues	$40,681	$48,846
Future lease operating expenses and production taxes	-21,284	-22,563
Future development costs	-140	-1,568
Future income taxes	-6,318	-7,225
Future net cash flows	12,939	17,490
10% annual discount for estimated timing of cash flows	-6,173	-9,156
Standardized measure of discounted future net cash flows	$6,766	$8,334

10_Oil_and_Gas_Producing_Activ8

10. Oil and Gas Producing Activities (Details 6) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Oil And Gas Producing Activities Details	'	'
Net changes in prices and production costs	($1,077)	$305
Sales and transfers of oil and gas produced	-1,292	-1,290
Net change due to revisions in quantity estimates	-603	395
Future development costs	673	-11
Net change in income taxes	136	477
Changes in production rates, other	-238	-1,272
Accretion of discount	833	885
Changes in standardized measure of discounted FCF	-1,568	-511
Beginning standardized measure of discounted FCF	8,334	8,845
Ending standardized measure of discounted FCF	$6,766	$8,334

10_Oil_and_Gas_Producing_Activ9

10. Oil and Gas Producing Activities (Details Narrative) (USD $)	12 Months Ended
	Dec. 31, 2013
Oil	'
Annual average price	$96.84
Gas	'
Annual average price	$3.41