UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

[X] QUARTERLY REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended ~~March~~June 3130, 2015

[ ] TRANSITION REPORT UNDER SECTION 13 OR 15(D) OF THE EXCHANGE ACT ~~OF 1934~~

For the transition period from ~~________~~__________ to ~~________~~__________

OSAGE EXPLORATION AND DEVELOPMENT, INC.

(Exact name of small business issuer as specified in its charter)

Delaware

0-52718

26-0421736

(State or other jurisdiction of

incorporation or organization)

(Commission
File No.)

(I.R.S. Employer
Identification No.)

2445 5^th Avenue

Suite 310

San Diego, CA 92101

(619) 677-3956

(Address of principal executive offices)

(Issuer’s telephone number)

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

Yes [X] No [ ]

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

Yes [ ] No [X]

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

Large Accelerated Filer [ ] Accelerated Filer [ ] Non-Accelerated Filer [ ] Smaller Reporting Company [X]

Non-Accelerated Filer [ ] Smaller Reporting Company [X]

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

Yes [ ] No [X]

The number of outstanding shares of the registrant’s common stock, $0.0001 par value, as of ~~May~~August 11, 2015 was 58,284,948.

OSAGE EXPLORATION AND DEVELOPMENT, INC. AND SUBSIDIARIES

TABLE OF CONTENTS

		Page
PART I – FINANCIAL INFORMATION
Item 1.	Financial Statements	~~F-1~~
	Consolidated Balance Sheets; March 31, 2015 (unaudited) and December 31, 2014	F-1
	Consolidated Balance Sheets; June 30, 2015 (unaudited) and December 31, 2014	F-1
	Consolidated Statements of Operations: Three Months ended March 31, 2015 (unaudited) and 2014 (unaudited)	F-2
	Consolidated Statements of Operations: Three and Six Months ended June 30, 2015 (unaudited) and 2014 (unaudited)	F-2
	Consolidated Statements of Cash Flows; Three Months ended March 31, 2015 (unaudited) and 2014 (unaudited)	F-3
	Consolidated Statements of Cash Flows; Six Months ended June 30, 2015 (unaudited) and 2014 (unaudited)	F-3
	Notes to Consolidated Financial Statements	F-4
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	3
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	1012
Item 4.	Controls and Procedures	1013
PART II – OTHER INFORMATION
Item 1.	Legal Proceedings	1113
Item 1.A.	Risk Factors	1113
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	1113
Item 3.	Default upon Senior Securities	1114
Item 4.	Mine Safety Disclosures	1114
Item 5.	Other Information	1114
Item 6.	Exhibits	1114
Signatures		1215

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

OSAGE EXPLORATION AND DEVELOPMENT, INC. AND SUBSIDIARIES

BALANCE SHEETS

As of ~~March~~June 3130, 2015 (unaudited) and December 31, 2014

	March 31, 2015			December 31, 2014
	June 30, 2015			December 31, 2014
ASSETS
Current assets:
Cash and equivalents	$	2577,~~428,569~~284		$	5,054,735
Accounts receivable		21,~~059~~440,~~540~~908			3,595,555
Unrealized gains on oil and gas derivatives		~~770~~121,~~833~~026			1,116,740
Prepaid expenses and other current assets		6674,~~275~~820			120,390
Deferred financing costs		~~819~~628,~~142~~642			1,009,642
Total current assets		62,~~144~~842,~~359~~680			10,897,062
Property and equipment, at cost:
Oil & gas properties and equipment (successful efforts method)		62,~~575~~221,~~262~~893			62,115,916
Other property & equipment		267,558			260,526
		62,842,820			62,376,442
		62,489,451			62,376,442
Less: accumulated depletion, impairment, depreciation and amortization		(4041,~~295~~145,~~096~~785	)		(39,270,342	)
		22,547,724			23,106,100
		21,343,666			23,106,100
Restricted cash		893,357			896,367
Total assets	$	2925,~~585~~079,~~440~~703		$	34,899,529
LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)
Current liabilities:
Accounts payable	$	1110,~~068~~489,~~867~~188		$	16,949,047
Joint interest liabilities		1,~~936~~894,~~213~~125			2,313,801
Revenues and royalties payable		31,~~874~~977,~~152~~323			1,761,634
Accrued expenses		~~351~~290,~~341~~770			1,039,945
Capital lease liability, current portion		42,~~503~~581			45,698
Notes payable		25,000,000			25,000,000
Total current liabilities		4239,~~273~~693,~~076~~987			47,110,125
Unrealized losses on oil and gas derivatives, net of current portion					-
Capital lease liability, net of current portion		28,559			50,135
Capital lease liability, net of current portion		39,221			50,135
Liability for asset retirement obligations		6,895			6,281
Liability for asset retirement obligations		6,586			6,281
Total liabilities		39,729,441			47,166,541
Total liabilities		42,318,883			47,166,541
Commitments and contingencies
Stockholders’ Equity (Deficit):
Preferred stock, $0.0001 par value, 10,000,000 authorized, none issued and outstanding as of March 31, 2015 or December 31, 2014		-			-
Preferred stock, $0.0001 par value, 10,000,000 authorized, none issuedand outstanding as of June 30, 2015 or December 31, 2014		-			-
Common stock, $0.0001 par value, 190,000,000 shares authorized; 58,284,948 and 58,098,014 shares issued and outstanding as of March 31, 2015 and December 31, 2014, respectively		5,828			5,809
Common stock, $0.0001 par value, 190,000,000 shares authorized; 58,284,948 and 58,098,014 shares issued and outstanding as of June 30, 2015 and December 31, 2014, respectively		5,828			5,809
Additional paid-in capital		26,842,382			26,551,541
Stock purchase notes receivable		(95,000	)		(95,000	)
Accumulated deficit		(3941,~~486~~402,~~653~~948	)		(38,729,362	)
Total stockholders’ equity (deficit)		(1214,~~733~~649,~~443~~738	)		(12,267,012	)
Total liabilities and stockholders’ equity (deficit)	$	2925,~~585~~079,~~440~~703		$	34,899,529

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

F-1

OSAGE EXPLORATION AND DEVELOPMENT, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

For the Three and Six Months ended ~~March~~June 3130, 2015 and 2014 (unaudited)

	Quarter Ended March 31,
	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
Operating revenues
Oil revenues	$	21,~~463~~760,~~828~~497		$	21,~~132~~895,~~817~~201		$	4,224,325		$	4,028,018
Natural gas and natural gas liquids revenues		~~446~~350,~~452~~552			~~504~~583,~~598~~495			797,004			1,088,093
Total operating revenues		2,~~910~~111,~~280~~049			2,~~637~~478,~~415~~696			5,021,329			5,116,111
Operating costs and expenses
Operating costs		704,922			473,142
Well operating costs		511,960			390,699			1,216,882			863,841
General and administrative expenses		1891,~~195,879~~454			~~843~~3,~~952~~643,408			2,087,333			4,487,360
Depreciation, depletion and accretion		1850,~~025,059~~998			~~999~~1,~~899~~346,123			1,876,057			2,346,022
Write off of expired mineral rights leases		~~141~~562,~~348~~846			-			704,194			-
Gain on sale of land interests		~~(197,905~~-	)		(7077,~~314~~950	)		(197,905	)		(148,264	)
Total operating costs and expenses		2,~~869~~817,~~303~~258			25,~~246~~302,~~679~~280			5,686,561			7,548,959
Operating income		40,977			390,736
Operating loss		(706,209	)		(2,823,584	)		(665,232	)		(2,432,848	)
Other income (expenses):
Interest income		~~1,298~~305			~~424~~4,409			1,603			4,833
Interest expense		(1,~~003~~062,~~213~~120	)		(1,~~210~~215,~~560~~579	)		(2,065,333	)		(2,426,139	)
Gain (loss) on oil and gas derivatives		~~203~~(148,~~647~~271	)		(~~115~~362,~~727~~995	)		55,376			(478,722	)
Loss before income taxes		(~~757~~1,~~291~~916,295	)		(~~935~~4,~~127~~397,749	)		(2,673,586	)		(5,332,876	)
Provision for income taxes		-			-			-			-
Net loss		(~~757~~1,~~291~~916,295	)		(~~935~~4,~~127~~397,749	)		(2,673,586	)		(5,332,876	)
Basic and diluted loss per share	$	(0.0103	)	$	(0.0208	)	$	(0.05	)	$	(0.10	)
Weighted average number of common share and common share equivalents used to compute basic and diluted loss per share		58,~~218~~284,~~483~~948			5158,~~602~~033,~~380~~570			58,241,330			54,817,975

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

F-2

OSAGE EXPLORATION AND DEVELOPMENT, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the ~~Three~~Six Months ended ~~March~~June 3130, 2015 and 2014 (unaudited)

	2015			2014
Cash flows from operating activities:
Net loss	$	(~~757~~2,~~291~~673,586	)	$	(~~935~~5,~~127~~332,876	)
Adjustments to reconcile net loss to net cash
Adjustments to reconcile net loss to net cash provided by operating activites:
provided by operating activites:
Stock based compensation		290,860			3,032,252
Stock based compensation		290,860			109,000
Amortization of deferred financing costs		381,000			538,482
Amortization of deferred financing costs		190,500			347,983
Gain on sale of land interests		(197,905	)		(148,264	)
Gain on sale of land interests		(197,905	)		(70,314	)
Write off of expired mineral rights leases		704,194			13,373
Write off of expired mineral rights leases		141,348			-
Accretion of asset retirement obligation		614			412
Accretion of asset retirement obligation		305			200
Provision for depletion, depreciation and amortization		1,875,443			2,345,610
Provision for depletion, depreciation and amortization		1,024,754			999,699
Unrealised loss on oil and gas derivatives		995,714			311,480
Unrealised loss on oil and gas derivatives		345,907			68,058
Changes in operating assets and liabilities:
Decrease in accounts receivable		12,~~536~~154,~~015~~647			~~388~~868,~~618~~372
Decrease in prepaid expenses and other current assets		5445,~~115~~570			~~537~~512,~~315~~605
(Decrease) increase in accounts payable and accrued expenses		(78,~~509~~089,~~505~~551	)		1317,~~854,500~~373
(Decrease) increase in joint interest billing account		(~~377~~419,~~588~~676	)		~~355~~2,~~894~~629,212
Increase in revenue and royalties payable		2215,~~112,518~~689			-
Net cash (used in) provided by operating activities		(34,~~145~~716,~~967~~987	)		35,~~655~~088,~~826~~031
Cash flows from investing activities:
Investments in oil & gas properties		(~~231~~500,~~250~~931	)		(39,~~955~~115,~~953~~107	)
Investments in non-oil & gas properties		(7,032	)		(4145,~~044~~844	)
Decrease in restricted cash		3,010			1637,680
Net proceeds from sale of land interests		769,182			~~104~~339,~~261~~165
Net cash provided by (used in) investing activities		~~533~~264,~~910~~229			(38,~~892~~784,~~720~~106	)
Cash flows from financing activities:
Net proceeds from offering of securities		-			6,~~066~~744,~~201~~000
Principal payments on capital leases		(14,109	)		(3,502	)
Proceeds from secured promissory notes		-			5,000,000
Principal payments on capital leases		(24,693	)		(14,022	)
Payment of placement fees and expenses		-			(437,100	)
Payment of deferred financing costs		-			(100,000	)
Proceeds from exercise of warrants		-			2,000
Net cash (used) provided by financing activities		(1424,~~109~~693	)		611,~~064~~194,~~699~~878
Net (decrease) increase in cash and equivalents		(24,~~626~~477,~~166~~451	)		57,~~827~~498,~~805~~803
Cash and equivalents - beginning of period		5,054,735			2,782,643
Cash and equivalents - end of period	$	2577,~~428,569~~284		$	810,~~610~~281,~~448~~446
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash payment for interest	$	~~812~~1,~~713~~684,333		$	~~862~~1,~~577~~887,657
SUPPLEMENTAL DISCLOSURE OF NON-CASH ACTIVITIES:
Increase in asset retirement obligation	$	-		$	39243
Oil & gas additions in accounts payable	$	~~940~~880,~~721~~517		$	-3,564,888
Purchase of furniture and fixtures through capital lease	$	-		$	127,435
Cashless exercise of warrants	$	19		$	-
Purchase of furniture and fixtures through capital leases	$	-		$	127,435

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

F-3

OSAGE EXPLORATION AND DEVELOPMENT, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

~~March~~June 3130, 2015 and 2014 (unaudited)

1. ORGANIZATION AND BASIS OF PRESENTATION

Osage Exploration and Development, Inc. (“Osage” or the “Company”) is an independent energy company engaged primarily in the acquisition, development, production and sale of oil, natural gas and natural gas liquids. The Company’s production activities are located in the State of Oklahoma. The principal executive offices of the Company are at 2445 Fifth Avenue, Suite 310, San Diego, CA 92101.

Osage prepared the accompanying unaudited consolidated financial statements in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”) for interim financial information and pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”) instructions to Form 10-Q and Item 310(b) of Regulation S-K. These financial statements should be read together with the financial statements and notes in the Company’s 2014 Form 10-K filed with the SEC. Certain information and footnote disclosures normally included in financial statements prepared in accordance with U.S. GAAP were condensed or omitted. The accompanying financial statements reflect all adjustments and disclosures, which, in the Company’s opinion, are necessary for fair presentation. All such adjustments are of a normal recurring nature. The results of operations for the interim periods are not necessarily indicative of the results to be expected for the entire year.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Going Concern

The Company has an accumulated deficit of $3941,~~486~~402,~~653~~948 and a working capital deficit of $36,~~128~~851,~~717~~307, as of ~~March~~June 3130, 2015. As of ~~March~~June 3130, 2015, as a result of production delays and ~~a general decline in~~ prevailing oil prices, the Company was not ~~able to operate profitably and was not~~ in compliance with certain covenants under the senior secured ~~note~~Note ~~purchase~~Purchase ~~agreement~~Agreement. (see Note 5 - Debt). ~~Without~~ ~~additional financing, the Company may not be able to fully implement its operating plan.~~ These factors raise substantial doubt about the Company’s ability to continue as a going concern.

On April 27, 2012, we entered into a $10,000,000 senior secured ~~note~~Note ~~purchase~~Purchase ~~agreement~~Agreement with Apollo Investment Corporation. On April 5, 2013 we amended this agreement, increasing the facility to $20,000,000. On April 3, 2014, the Company and Apollo amended the Note Purchase Agreement, increasing the amount of the total facility to $30,000,000, extending the term by one year and reducing the interest rate from Libor plus 15% to Libor plus 11%. During the year ended December 31, 2014, we drew down $5,000,000 of additional funds and, as of December 31, 2014 and ~~March~~June 3130, 2015, the amount outstanding under the senior secured ~~note~~Note ~~purchase~~Purchase ~~agreement~~Agreement was $25,000,000.

~~Management~~In ofearly 2014, the Company ~~has~~raised ~~undertaken~~approximately ~~steps as part of a plan to improve operations with the goal of sustaining our operations for the next 12 months and beyond~~$6.7 ~~These~~million ~~steps include (a) becoming operators~~ of ~~our~~gross ~~own~~proceeds ~~wells, (b) participating~~ in ~~drilling~~a ofprivate ~~wells in Logan County, Oklahoma within the next 12 months, (c) controlling overhead and expenses, (d) selling portions of existing operations, and (e) raising additional equity and/or debt~~placement.

~~The~~Management ~~Company’s~~of ~~operating~~the ~~plans~~Company ~~require~~has ~~additional~~undertaken ~~funds~~steps ~~which~~as ~~may~~part ~~take the form~~ of ~~debt~~a orplan ~~equity financings. The Company’s ability~~ to ~~continue~~improve ~~as a going concern is dependent upon achieving profitable~~ operations ~~and~~with ~~obtaining~~the ~~additional~~goal ~~financing.~~of ~~Our cash~~sustaining ~~flows~~our ~~and results of~~ operations ~~depend~~for ~~to a great extent on~~ the next ~~prevailing~~12 ~~prices~~months ~~for oil~~ and ~~gas~~beyond. ~~Prolonged~~These orsteps ~~substantial declines~~include in(i) ~~oil~~seeking /potential merger and~~/or~~ ~~gas~~combination ~~prices~~opportunities, ~~may~~(ii) ~~materially~~attempting ~~and~~to refinance ~~adversely~~our ~~affect~~current ~~our~~debt ~~liquidity,~~with ~~the~~some ~~amount~~combination of ~~cash~~new ~~flows~~debt weand ~~have~~equity, ~~available for our capital expenditures~~ and ~~other~~(iii) ~~operating~~considering ~~expenses,~~the ~~our~~potential ~~ability~~acquisition toof ~~access credit~~ oil and ~~capital~~gas ~~markets~~properties ~~and~~for ~~our~~equity; ~~results~~all ~~of operations.~~in ~~There~~an iseffort noto ~~assurance~~stabilize ~~additional~~the ~~funds~~Company ~~will~~and beprovide ~~available~~an onincreased ~~acceptable~~base ~~terms~~of oroperating atcash ~~all~~flow.

In the event an event of default is declared and continues under the Note Purchase Agreement, the lender can take certain actions, including demanding immediate repayment of all amounts then outstanding or initiating foreclosure proceedings against us. As the Note Purchase Agreement is secured by substantially all of our assets, there is a risk that if the lender were to request the immediate repayment of the amounts outstanding and we did not have, and could not timely raise, funds to repay such obligations, that the lender (or where applicable, its agent) could foreclose on our assets which could cause us to significantly curtail or cease operations. If amounts outstanding under such Note Purchase Agreement were to be accelerated in the event of the occurrence of an event of default under the Note Purchase Agreement or the continuation thereof, our assets might not be sufficient to repay in full that indebtedness and our other indebtedness and we may not be able to raise funds from alternative sources to repay such obligations on favorable terms, on a timely basis, or at all. As such, the value of our securities may decline in value or become worthless in the event our lender accelerates the repayment of our outstanding obligations. Additionally, such defaults may harm our credit rating and our ability to obtain additional financing on acceptable terms.

The Company’s operating plans require additional funds which may take the form of debt or equity financings. The Company’s ability to continue as a going concern is dependent upon achieving profitable operations and obtaining additional financing. Our cash flows and results of operations depend to a great extent on the prevailing prices for oil and gas. Prolonged or substantial declines in oil / and/or gas prices may materially and adversely affect our liquidity, the amount of cash flows we have available for our capital expenditures and other operating expenses, our ability to access credit and capital markets and our results of operations. There is no assurance additional funds will be available on acceptable terms or at all. In the event the Company is unable to continue as a going concern, management may elect or be required to seek protection from creditors by filing a voluntary petition in bankruptcy or may be subject to an involuntary petition in bankruptcy.

These consolidated financial statements do not give effect to any adjustments which would be necessary should the Company be unable to continue as a going concern and therefore be required to realize its assets and discharge its liabilities in other than the normal course of business and at amounts different from those reflected in the accompanying consolidated financial statements.

Basis of Consolidation

The consolidated financial statements include the accounts of Osage and its wholly owned subsidiaries, Osage Energy Company, LLC and Osage Exploration and Development Operating, LLC. Accordingly, all references herein to Osage or the Company include the consolidated results. All significant inter-company accounts and transactions were eliminated in consolidation.

F-4

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (“US GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Management used significant estimates in determining the carrying value of its oil and gas producing assets and the associated impairment, depreciation and depletion expense related to sales volumes. The significant estimates included the use of proved oil and gas reserve volumes and the related present value of estimated future net revenues there-from.

Reclassifications

Certain amounts included in the prior year financial statements have been reclassified to conform to the current year’s presentation. These reclassifications have no effect on the reported results in 2015 or 2014.

Risk Factors Related to Concentration of Sales and Products

The Company’s future financial condition and results of operations depend upon prices received for its oil and natural gas and the costs of finding, acquiring, developing and producing reserves. Prices for oil and natural gas are subject to fluctuations in response to changes in supply, market uncertainty and a variety of other factors beyond the Company’s control. These factors include worldwide political instability (especially in the Middle East), the foreign supply of oil and natural gas, the price of foreign imports, the level of consumer product demand and the price and availability of alternative fuels.

Cash and Equivalents

Cash and equivalents consist of short-term, highly liquid investments readily convertible into cash with an original maturity of three months or less.

Concentration of Credit Risk

Financial instruments that potentially subject the Company to concentrations of credit risk are cash and accounts receivable arising from its normal business activities. The Company places its cash in what it believes are credit-worthy financial institutions. However, the Company’s cash balances have exceeded the FDIC insured levels at various times during the ~~three~~six months ended ~~March~~June 3130, 2015 and 2014. The Company maintains cash accounts only at large, high quality financial institutions and believes the credit risk associated with cash held in banks exceeding the FDIC insured levels is remote. The Company generated substantially all of its revenues from ~~seven customers and~~ four customers in the three and six months ended ~~March~~June 3130, 2015 and ~~March~~June 3130, 2014, respectively.

Deferred Financing Costs

The Company incurred deferred financing costs in connection with the Note Purchase Agreement (see Note 5), which represented the fair value of warrants, placement fees and legal fees. Deferred financing costs of $3,959,448 are being amortized over the term of the Note Purchase Agreement on a straight-line basis, which approximates the effective interest method. In 2014, the term of the Note Purchase Agreement was extended by one year.

Deferred financing costs net of accumulated amortization at ~~March~~June 3130, 2015 were $~~819~~628,~~142~~642. Amortization of deferred financing costs was $190,500 and $381,000 for the three and six months ended ~~March~~June 3130, 2015, respectively and $~~347~~190,~~983~~499 and $538,482 for the three ~~months~~and six months ended ~~March~~June 3130, 2014, respectively.

Restricted Cash

In connection with the Apollo Note Purchase Agreement, as amended (see Note 5), the Company has classified $812,500, representing three months interest, as restricted cash as of ~~March~~June 3130, 2015 and December 31, 2014, respectively. The Company has also pledged $80,857 and $83,867 for certain bonds and sureties at ~~March~~June 3130, 2015 and December 31, 2014, respectively. Restricted cash at ~~March 31~~June 30, 2015 was $893,357, compared to $896,367 at December 31, 2014.

F-5

Risk Management Activities

The Company has entered into certain derivative financial instruments to manage the inherent uncertainty of future revenues. The Company does not intend to hold or issue derivative financial instruments for speculative purposes and has elected not to designate any of its derivative instruments for hedge accounting treatment. These derivative financial instruments are marked to market at each reporting period.

~~F-5~~Net Income/Loss Per Share

~~Net~~In ~~Loss~~accordance with Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 260 “Earnings Per Share,” the Company’s basic net income/loss per share of common stock is calculated by dividing net income/loss by the weighted-average number of shares of common stock outstanding for the period. The diluted net income/loss per share of common stock is computed by dividing the net income/loss using the weighted-average number of common shares including potential dilutive common shares outstanding during the period. Potential common shares are excluded from the computation of diluted net loss per share if anti-dilutive.

InThe ~~accordance~~following ~~with~~table ~~Financial~~shows ~~Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 260 “Earnings Per Share,”~~ the ~~Company’s~~computation ~~basic net loss per share~~ of ~~common~~basic ~~stock~~and ~~is calculated by dividing net loss by the weighted-average number of shares of common stock outstanding for the period. The~~ diluted net income (loss) per share ~~of common~~for ~~stock is computed by dividing~~ the ~~net~~three ~~loss~~and ~~using~~six ~~the~~months ~~weighted-average~~ended ~~number of common shares including potential dilutive~~June ~~common~~30, ~~shares~~2015 ~~outstanding~~and ~~during the period. Potential common shares are excluded from the computation of diluted net loss per share if anti-dilutive.~~2014:

The following table shows the computation of basic and diluted net loss per share for the three months ended March 31, 2015 and 2014:

	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014

Net loss	$	(1,916,295	)	$	(4,397,749	)	$	(2,673,586	)	$	(5,332,876	)

Basic and diluted net loss per share	$	(0.03	)	$	(0.08	)	$	(0.05	)	$	(0.10	)

Basic and diluted weighted average shares outstanding		58,284,948			58,033,570			58,241,330			54,817,975

	Three Months Ended March 31,
		2015			2014
Net loss	$	(757,291	)	$	(935,127	)
Basic and diluted net loss per share	$	(0.01	)	$	(0.02	)
Basic and diluted weighted average shares outstanding		58,218,483			51,602,380

Potential common shares consisted of 8,394,179 and 7,287,559 warrants and options to purchase common stock at June 30, 2015 and 2014, respectively. All of these warrants and options were excluded from the computations for the three and six months ended June 30, 2015 and 2014, as their effect would have been anti-dilutive.

Potential common shares consisted of 8,394,179 and 4,531,392 warrants and options to purchase common stock at March 31, 2015 and 2014, respectively. All of these warrants and options were excluded from the computations for the three months March 31, 2015 and 2014, as their effect would have been anti-dilutive.

Impairment of Long-Lived Assets

The Company follows the guidance provided under FASB ASC Topic 360 (“ASC 360”), “Accounting for the Impairment or Disposal of Long-Lived Assets”, which addresses financial accounting and reporting for the impairment or disposal of long-lived assets. The Company periodically evaluates the carrying value of long-lived assets to be held and used in accordance with ASC 360. ASC 360 requires impairment losses to be recorded on long-lived assets used in operations when indicators of impairment are present and the undiscounted cash flows estimated to be generated by those assets are less than the assets’ carrying amounts. In that event, a loss is recognized based on the amount by which the carrying amount exceeds the fair market value of the long-lived assets. Loss on long-lived assets to be disposed of is determined in a similar manner, except that fair market values are reduced for the cost of disposal. During the three or six months ended ~~March~~June 3130, 2015 and 2014, the Company did not record impairment charges related to its long-lived assets.

Fair Value of Financial Instruments

As of ~~March~~June 3130, 2015 and December 31, 2014, the fair value of cash, accounts receivable, short term debt and accounts payable approximate carrying values because of the short-term maturity of these instruments.

Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 820, “Fair Value ~~Measurements~~ Measurements and Disclosures,” requires disclosure of the fair value of financial instruments held by the Company. ASC Topic 825, “Financial Instruments,” defines fair value, and establishes a three-level valuation hierarchy for disclosures of fair value measurement that enhances disclosure requirements for fair value measures. The carrying amounts reported in the consolidated balance sheets for receivables and current liabilities each qualify as financial instruments and are a reasonable estimate of their fair value because of the short period of time between the origination of such instruments and their expected realization and their current market rate of interest.

The three levels of valuation hierarchy are defined as follows:

	●	Level 1 inputs to the valuation methodology are quoted prices for identical assets or liabilities in active markets.

	●	Level 2 inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, quoted prices for identical or similar assets in inactive markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument.

	●	Level 3 inputs to the valuation methodology use one or more unobservable inputs which are significant to the fair value measurement.

The Company analyzes all financial instruments with features of both liabilities and equity under ASC Topic 480, “Distinguishing Liabilities from Equity,” and ASC Topic 815, “Derivatives and Hedging.”

As of ~~March~~June 3130, 2015 and December 31, 2014, the Company identified certain derivative financial instruments which required disclosure at fair value on the balance sheet.

F-6

The following table presents information for those assets and liabilities requiring disclosure at fair value as of ~~March~~June 3130, 2015 ~~and~~ and December 31, 2014:.

Total

Fair Value Measurements Using:

Carrying

Fair

Level 1

Level 2

Level 3

Amount

Value

Inputs

March 31, 2015 assets (liabilities):

June 30, 2015 assets (liabilities):

Commodity derivative asset

~~770~~121,~~833~~026

December 31, 2014 assets (liabilities):

Commodity derivative asset

1,116,740

The following methods and assumptions were used to estimate the fair values in the tables above.

Level 2 Fair Value Measurements

Commodity derivatives — The fair values of commodity derivatives are estimated using internal option pricing models based upon forward curves and data obtained from independent third parties for contracts with similar terms or data obtained from counterparties to the agreements.

Assets and Liabilities Measured on a Non-Recurring Basis

The Company utilizes fair value on a non-recurring basis to perform impairment tests on its oil ~~and~~& gas properties when required. During the year ended December 31, 2014, the Company recognized impairment on proved oil ~~and~~& gas properties of $29,858,178. ~~These~~ These proved oil ~~and~~& gas properties are located in the Logan County Field in Oklahoma and the fair value evaluation was performed on on a field basis. The factors used to determine fair value are subject to our judgment and expertise and include, but are not ~~limited~~ limited to, recent actual or proposed sales prices of comparable properties, the present value of future cash flows, net of estimated operating and development costs using estimates of proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures, and various discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flows projected and would generally be classified within Level 3.

Carrying

Amount

Total

Fair Value Measurements Using:

(before

Fair

Level 1

Level 2

~~Level 3~~

Level 3

impairment)

Value

Inputs

~~Inputs~~

Inputs

December 31, 2014 assets (liabilities):

Proved oil and gas properties, net book value

50,872,404

21,014,226

Proved oil & gas properties, net book value

50,872,404

21,014,226

Recent Accounting Pronouncements

In May 2014, the FASB issued Accounting Standards Update (“ASU”) 2014-09, Revenue from Contracts with Customers. The ASU will supersede most of the existing revenue recognition requirements in GAAP and will require entities to recognize revenue at an amount that reflects the consideration to which it expects to be entitled in exchange for transferring goods or services to a customer. The new standard also requires disclosures sufficient to enable users to understand an entity’s nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. In April 2015, the FASB proposed a one-year deferral of the effective date of the new standard. IfThe ~~approved, the~~ new standard will be effective for the Company in fiscal 2018. Early application is not permitted. The standard permits the use of either the retrospective or cumulative effect transition method.

In August 2014, the FASB issued ASU 2014-15, Presentation of Financial Statements—Going Concern: Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern, which provides guidance on determining when and how reporting entities must disclose going-concern uncertainties in their financial statements. The new standard requires management to perform interim and annual assessments of an entity’s ability to continue as a going concern within one year of the date of issuance of the entity’s financial statements. Further, an entity must provide certain disclosures if there is substantial doubt about the entity’s ability to continue as a going concern. The ASU is effective for annual periods ending after December 15, 2016 and interim periods thereafter, and early adoption is permitted.

The Company is evaluating the impact, if any, that ASU 2014-09 and ASU 2014-15 will have on its consolidated financial statements.

In April 2015, the FASB issued ASU 2015-03, Simplifying the Presentation of Debt Issuance Costs. The standard requires debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected. The standard will become effective for the Company beginning January 1, 2016. The implementation of this standard is not expected to have a significant impact on our consolidated financial statements.

F-7

3. OIL AND GAS PROPERTIES

Oil and gas properties consisted of the following:

	March 31, 2015			December 31, 2014
	June 30, 2015			December 31, 2014
Properties subject to amortization	$	60,609,983		$	60,168,713
	(unaudited)
Properties not subject to amortization		1,960,121			1,942,045
Properties subject to amortization	$	60,113,179		$	60,168,713
Properties not subject to amortization		2,103,557			1,942,045
Capitalized asset retirement costs		5,158			5,158
Accumulated impairment, depreciation and depletion		(4041,~~169~~010,~~572~~122	)		(39,154,487	)
Oil & Gas Properties, Net	$	2221,~~405~~211,~~690~~772		$	22,961,429

Depreciation and depletion expense for oil and gas properties totaled $1840,~~015,085~~550 and $~~992~~1,~~952~~855,635 in the three and six months ended ~~March~~June 3130, 2015, respectively and $1,344,307 and $2,327,259 in the three and six months ended June 30, 2014, respectively.

On April 21, 2011, the Company entered into a participation agreement (“Participation Agreement”) with Slawson Exploration Company (“Slawson”) and U.S. Energy Development Corporation (“USE,” Slawson and USE, together, the “Parties”). Pursuant to the terms of the Participation Agreement, Slawson and USE acquired 45% and 30% respectively, of our 10,000 acre Nemaha Ridge prospect in Logan County, Oklahoma for $4,875,000. In addition, the Parties carried Osage for 7.5% of the cost of the first three horizontal Mississippian wells, which means that for the first three horizontal Mississippian wells, the Company provided up to 17.5% of the total well costs. After the first three wells, the Company was responsible for up to 25% of the total well costs. Revenue from wells drilled pursuant to the Participation Agreement, after royalty and third party acreage interest payments, was allocated 45% to Slawson, 30% to USE and 25% to Osage. Slawson was the operator of all wells in the Nemaha Ridge prospect in sections where the Parties’ acreage controlled the section. In sections where the Parties’ acreage did not control the section, we may elect to participate in wells operated by others.

On December 12, 2013, Osage and Slawson entered into an agreement (the “Partition Agreement”) related to certain lands located within the Nemaha Ridge in Logan County, Oklahoma, and for the exploration and development of those leases by the Parties.

Under the Partition Agreement and effective as of September 1, 2013, the Slawson Exploration Group agreed to assign all of its rights, title and interest in and to the oil and gas leases and force-pooled acreage which are part of the Nemaha Ridge Project within certain sections to Osage and Osage agreed to assign all of its rights, title and interest in and to the oil and gas leases and force-pooled acreage which are part of the Nemaha Ridge Project within certain sections to the Slawson Exploration Group, such that the net acreage controlled by the parties would remain substantially unchanged, but that the acreage controlled by each of the parties in undeveloped sections would be located in sections where the other party did not control acreage. The parties also agreed that the Participation Agreement would terminate as to all lands within the Nemaha Ridge Project except for lands within sections already developed by the parties which shall continue to be controlled by the Participation Agreement.

In September 2014, Slawson sold its interests in its oil and gas properties in Logan County, Oklahoma to Stephens Energy Group, LLC and Stephens Production Company (collectively “Stephens”).

As a result of the Partition Agreement, Osage has become the project operator on much of its acreage in the Nemaha Ridge Project. As of ~~March~~June 3130, 2015, Osage operated or has the right to operate approximately 4,~~876~~765 net acres (7,~~601~~602 gross), and remains joint-venture or potential joint-venture partners with others in approximately 4,~~854~~787 net acres (3134,~~754~~467 gross).

In 2011, we also began to acquire leases in Coal County, Oklahoma, targeting the Woodford Shale formation. The Woodford Shale formation is located mainly in southeastern Oklahoma in the Arkoma Basin. The Woodford shale lies directly under the Mississippian and started as a vertical play, but horizontal drilling techniques and multi-stage fracturing technology have been used in the Woodford in recent years with much success. At ~~March~~June 3130, 2015, we had 32,~~037~~716 net (7,~~502~~306 gross) acres leased in Coal County.

In 2011, the Company began to acquire leases in Pawnee County, Oklahoma, targeting the Mississippian formation. In July 2011, we purchased from B&W Exploration, Inc. (“B&W”) the Pawnee County prospect targeting the Mississippian, for $8,500. In addition, B&W is also entitled to an overriding royalty interest on the leases acquired and a 12.5% carry on the first $200,000 of lease bonus paid in the form of an assignment of 12.5% of the leases acquired. Subsequently, B&W shall have an option to purchase a 12.5% share of leasehold acquired on a heads-up basis. As of March 31, 2015, the Company had 2,886 net acres (3,784 gross) leased in Pawnee County.

F-8

AtIn ~~March~~2011, 31the Company began to acquire leases in Pawnee County, ~~2015~~Oklahoma, targeting the Mississippian formation. In July 2011, we purchased ~~have~~from ~~leased~~B&W 15Exploration,~~653~~ ~~net~~Inc. (50“B&W”) the Pawnee County prospect targeting the Mississippian,~~641~~ ~~gross)~~for ~~acres~~$8,500. In ~~across~~addition, ~~three~~B&W ~~counties~~is also entitled to an overriding royalty interest on the leases acquired and a 12.5% carry on the first $200,000 of lease bonus paid in ~~Oklahoma~~the asform ~~follows:~~of an assignment of 12.5% of the leases acquired. Subsequently, B&W shall have an option to purchase a 12.5% share of leasehold acquired on a heads-up basis. As of June 30, 2015, the Company had 2,113 net acres (3,491 gross) leased in Pawnee County.

	Gross		Osage Net
Logan - non-operated		31,754		4,854
Logan - Osage		7,601		4,876
Coal		7,502		3,037
Pawnee		3,784		2,886
		50,641		15,653

At June 30, 2015, we have leased 14,381 net (52,866 gross) acres across three counties in Oklahoma as follows:

	Gross		Osage Net
Logan - non-operated		34,467		4,787
Logan - Osage		7,602		4,765
Coal		7,306		2,716
Pawnee		3,491		2,113
		52,866		14,381

4. SEGMENT AND GEOGRAPHICAL INFORMATION

At ~~March~~ 31June 30, 2015 ~~and December 31~~, ~~2014,~~ the Company’s operations comprised one segment in one geographic region.

5. DEBT

Apollo - Note Purchase Agreement

On April 27, 2012, we entered into a $10,000,000 senior secured note purchase agreement (“Note Purchase Agreement” or “Notes”) with Apollo Investment Corporation (“Apollo”). The Notes, which mature on April 27, ~~2015~~2016, are secured by substantially all of the assets of the Company, including a mortgage on all our Oklahoma leases. The Notes bear interest of Libor plus 15.0% with a Libor floor of 2.0%, with interest payable monthly. In addition, Apollo received a warrant to purchase 1,496,843 shares of common stock, exercisable at $0.01 per share, with a Black-Scholes value of $2,483,952 and an expiration date of April 27, 2017. Variables used in the valuation include (1) discount rate of 0.82%, (2) expected life of 5 years, (3) expected volatility of 245.0% and (4) zero expected dividends. The minimum draw amount on the Note Purchase Agreement is $1,000,000. At closing, we did not draw down any funds. In the year ended December 31, 2013, we drew down $17,000,000 and, as of December 31, 2013, the amount outstanding under the Note Purchase Agreement was $20,000,000.

At closing of the Note Purchase Agreement, we paid $100,000 of a minimum placement fee to CC Natural Resource Partners, LLC (“CCNRP”) and issued a warrant to purchase 250,000 shares of common stock, exercisable at $0.01 per share, with a Black-Scholes value of $413,690 and an expiration date of April 27, 2014. Variables used in the valuation include (1) discount rate of 0.26%, (2) expected life of 2 years, (3) expected volatility of 242.0% and (4) zero expected dividends. In addition, we paid $170,692 in legal fees, of which $100,000 were paid to Apollo. In December 2012, we paid an additional $380,000 in placement fees. We also issued a warrant to purchase 100,000 shares of common stock, exercisable at $0.01 per share, with a Black-Scholes value of $89,952 and a term of five years, to the placement agent for the Note Purchase Agreement and amended the term of the warrant granted on April 27, 2012 from two to five years, with a Black-Scholes value of $1,161. Variables used in the valuation include (1) discount rate of 0.72%, (2) expected life of five years, (3) expected volatility of 242.0% and (4) zero expected dividends. In December 2013 we paid an additional $100,000 in placement fees.

On April 5, 2013 the Company and Apollo amended the Note Purchase Agreement, increasing the amount of the facility to $20,000,000 and modifying certain covenants for the remainder of the Note Purchase Agreement term. The amendment also provided a waiver of certain covenants as of ~~March~~June 3130, 2013, as the Company did not meet certain covenants including the minimum production covenant as of that date. The Company paid an amendment fee of $100,000 which is being amortized over the remaining term of the Note Purchase Agreement.

On August 12, 2013, the Company and Apollo amended the Note Purchase Agreement. The amendment required that the Company, within 75 days of the effective date as defined in the amendment, complete either (1) a sale of certain assets, or (2) the issuance of capital stock in a transaction that resulted in aggregate net proceeds as defined in the amendment. In the event that the Company did not complete either one of the aforementioned transactions, the Company would have been required under the terms of the amendment to issue to Apollo additional warrants equivalent to three percent of the Company’s common stock, on a fully-diluted basis. On October 7, 2013 the Company completed the sale of its membership interests in Cimarrona LLC. This sale satisfied the requirements of the amendment and the Company is thus not obligated to issue additional Warrants to Apollo.

On April 3, 2014, the Company and Apollo amended the Note Purchase Agreement, increasing the amount of the total facility to $30,000,000, extending the term by one year and reducing the interest rate from Libor plus 15% to Libor plus 11%. In the year ended December 31, 2014, we drew down $5,000,000 and, as of March 31, 2015 and December 31, 2014, the amount outstanding under the Note Purchase Agreement was $25,000,000.

F-9

On April 3, 2014, the Company and Apollo amended the Note Purchase Agreement, increasing the amount of the total facility to $30,000,000, extending the term by one year and reducing the interest rate from Libor plus 15% to Libor plus 11%. In the year ended December 31, 2014, we drew down $5,000,000 and, as of June 30, 2015 and December 31, 2014, the amount outstanding under the Note Purchase Agreement was $25,000,000.

The Company has recorded deferred financing costs in the aggregate amount of $3,959,448 in connection with the Note Purchase Agreement, which represented the fair value of warrants issued to Apollo and CCNRP, placement fees, amendment fees and legal fees, which are amortized on a straight-line basis over the term of the Notes, which approximates the effective interest method, as the Company did not draw funds at issuance.

On each anniversary of the closing date, the Company is obligated to pay an administrative fee of $50,000. The Company is subject to certain precedents in connection with each draw, an upfront fee equal to 2.0% of the principal amount of each draw, and is required to maintain a deposit account equal to three months of interest payments.

The Company is subject to various affirmative, negative and financial covenants under the Note Purchase Agreement as amended along with other restrictions and requirements, all as defined in the Note Purchase Agreement. Affirmative covenants include by October 31st of each year beginning in 2012, a reserve report prepared as of the immediately preceding September 30, concerning the Company’s domestic oil and gas properties prepared by approved petroleum engineers, and thereafter as of September 30th of each year.

The Company was not in compliance with certain covenants under the Note Purchase Agreement as of ~~March~~June 3130, 2015 and December 31, 2014, due to production delays and ~~a general decline in~~ prevailing oil prices. Accordingly and because the Notes mature on April 27, 2016, the Company has classified borrowings under the Note Purchase Agreement as short term in the accompanying consolidated balance sheets.

Use of proceeds is limited to those purposes specified in the Note Purchase Agreement. The Notes are subject to mandatory prepayment in the event of certain asset sales, insurance or condemnation proceeds, issuance of indebtedness, extraordinary receipts and tax refunds. All terms are as defined in the Note Purchase Agreement.

In connection with the Note Purchase Agreement and certain capital leases, the Company recognized $1,~~003~~062,~~213~~120 of interest expense, of which $~~812~~190,~~713~~500 was non-cash interest expense and $871,620 was cash interest expense, for the three months ended ~~March~~June 3130, 2015. For the six months ended June 30, 2015, the Company recognized $2,065,333 of interest expense related to this facility, of which $381,000 was non-cash interest expense and $1,~~210~~684,~~560~~333 ofwas cash interest expense. The Company recognized $1,215,579 of interest expense, of which $~~862~~190,~~577~~499 was non-cash interest expense and $1,025,080 was cash interest expense, for the three months ended June ~~March~~30, 312014. For the six months ended June 30, 2014, the Company recognized $2,426,139 of interest expense related to this facility, of which $538,482 was non-cash interest expense and $1,887,657 was cash interest expense.

6. DERIVATIVE FINANCIAL INSTRUMENTS

The Company entered into certain derivative financial instruments with respect to a portion of its oil and gas production. These instruments are used to manage the inherent uncertainty of future revenues due to commodity price volatility and currently include only costless price collars. The Company does not intend to hold or issue derivative financial instruments for speculative trading purposes and has elected not to designate any of its derivative instruments for hedge accounting treatment.

AsThese ~~of March 31, 2015, the Company had the following open~~ oil ~~derivative positions. These oil~~ derivatives ~~settle~~settled against the average of the daily settlement prices for the WTI first traded contract month on the New York Mercantile Exchange (“NYMEX”) for each successive day of the calculation period. As of June 30, 2015, the Company had no open oil or natural gas derivative positions.

Price Collars

Monthly

Weighted Average

Volume

Floor Price

Ceiling Price

Period

(BBLs/m)

($/BBL)

Q2, 2015

6,000

80.00

93.50

As of March 31, 2015, the Company had the following open natural gas derivative positions. These natural gas derivatives settle against the NYMEX Penultimate for the calculation period.

Price Collars

Monthly

Weighted Average

Volume

Floor Price

Ceiling Price

Period

(Btu/m)

($/Btu)

Q2, 2015

10,000

3.75

4.40

Cash settlements and unrealized gains and losses on fair value changes associated with the Company’s commodity derivatives are presented in the “Gain (loss) on oil and gas derivatives’ caption in the accompanying consolidated statements of earnings.

F-10

The following table sets forth the cash settlements and unrealized gains and losses on fair value changes for commodity derivatives for the three and six months ended ~~March~~June 3130, 2015 and 2014.

	Three Months Ended			~~Three~~Six Months Ended
	March 31, 2015			March 31, 2014
	June 30, 2015			June 30, 2015
Cash settlements to (by) Company	$	549,554		$	(47,669	)
Cash settlements to Company	$	501,536		$	1,051,090
Unrealized losses on commodity derivatives		(~~345~~649,~~907~~807	)		(68995,~~058~~714	)
Gain (loss) on oil and gas derivatives	$	~~203~~(148,~~647~~271	)	$	~~(115~~55,~~727~~376	)

On October 15, 2013, the Company entered into an Intercreditor Agreement with Apollo and BP Energy Company to provide collateral for its oil and gas derivative financial instruments. BP Energy Corporation North America simultaneously provided a Guarantee for $25 million as collateral for BP Energy Company’s obligations to the Company.

	Three Months Ended			Six Months Ended
	June 30, 2014			June 30, 2014
Cash settlements to (by) Company	$	(119,572	)	$	(167,242	)
Unrealized losses on commodity derivatives		(243,423	)		(311,480	)

Loss on oil and gas derivatives	$	(362,995	)	$	(478,722	)

7. COMMITMENTS AND CONTINGENCIES

Environment

Osage, as owner 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 owner of real property and the lessee under oil and gas leases for the cost of pollution clean-up resulting from operations, subject the owner/lessee to liability for pollution damages and impose restrictions on the injection of liquids into subsurface strata. Although Company environmental policies and practices are designed to ensure compliance with these laws and regulations, future developments and increasing stringent regulations could require the Company to make additional unforeseen environmental expenditures. The Company maintains insurance coverage it believes is customary in the industry, although it is not fully insured against all environmental risks. The Company is not aware of any environmental claims existing as of ~~March~~June 3130, 2015, that would have a material impact on its consolidated financial position or results of operations. There can be no assurance, however, that current regulatory requirements will not change, or past non-compliance with environmental laws will not be discovered on the Company’s property.

Operating Leases

In February 2011, the Company entered into a 36 month lease for its corporate offices in San Diego. In February 2014, the Company amended this lease to extend the term for an additional three years through February 2017. In February 2012, the Company entered into a 24 month lease for a vehicle to be utilized by its operations in Oklahoma and entered into a 36 month lease for a vehicle at the termination of the original auto lease. In December 2013, the Company entered into a three year lease for office space in Oklahoma City the term for which commenced in February 2014.

Rental expense totaled $4445,~~163~~337 and $3044,~~939~~028 in the three months ended ~~March~~June 3130, 2015 and 2014, respectively, and $89,500 and $74,967 in the six months ended June 30, 2015 and 2014, respectively.

~~Future minimum commitments under operating leases are as follows as of March 31, 2015:~~F-11

Year		Amount
2015 (April - December)		138,764
2016		186,314
2017		29,862
	$	354,940

Future minimum commitments under operating leases are as follows as of June 30, 2015:

Year	Amount

2015 (June - December)		92,509
2016		186,314
2017		29,862
	$	308,685

Capital leases

The Company entered into a lease for certain office furniture and equipment in the first quarter of 2014. The term of the lease is three years and as the lease essentially transfer the risks of ownership it is being accounted for as a capital lease.

~~F-11~~Leased property under capital leases at June 30, 2015 includes:

Leased property under capital leases at March 31, 2015 includes:

	June 30, 2015
Furniture and equipment	$	127,436
less: accumulated depreciation		(33,984	)
	$	93,452

		March 31, 2015
Furniture and equipment	$	127,436
less: accumulated depreciation		(27,612	)
	$	99,824

Total depreciation expense under capital leases was $6,372 for the three months ended June 30, 2015 and 2014, respectively, and $12,744 and $8,496 for the six months ended June 30, 2015 and 2014, respectively. As of June 30, 2015, the future minimum lease payments under capital leases were as follows:

Total depreciation expense under capital leases was $6,372 and $2,124 for the three months ended March 31, 2015 and 2014, respectively. As of March 31, 2015, the future minimum lease payments under capital leases were as follows:

Year	Amount

2015 (June - December)		21,478
2016		42,956
2017		7,160
		71,594
Less amount representing interest		(454	)
Present value of minimum lease payments	$	71,140

Current maturities	$	42,581
Non-current maturities		28,559
	$	71,140

Year	Amount
2015 (April - December)		32,217
2016		42,956
2017		7,158
		82,331
Less amount representing interest		(607	)
Present value of minimum lease payments	$	81,724
Current maturities	$	42,503
Non-current maturities		39,221
	$	81,724

Legal Proceedings

The Company has initiated litigation against Stephens with respect to their right to operate 22 wells in which we have a working interest as we contend that we should be the operator. ~~The~~Certain vendors have recorded Workmen’s Liens against certain properties of which the Company is ~~not~~the aoperator, ~~party~~due to ~~any~~amounts ~~other~~outstanding ~~litigation~~to ~~that~~them ~~has~~for ~~arisen~~work inperformed at these properties. These Liens have generally been filed due to specific time limitations within which vendors must record the ~~normal~~Liens under Oklahoma law. Additionally, ~~course~~three ofvendors ~~its~~have ~~business~~initiated orlegal ~~that~~actions against the Company over non-payment of ~~its~~certain ~~subsidiaries~~amounts due. These actions have been stayed to allow the Company some time to pursue financing alternatives.

Sale of Cimarrona LLC

On October 7, 2013, the Company completed the sale of 100% of the membership interests in Cimarrona LLC to Raven Pipeline Company, LLC (“Raven”), pursuant to a Membership Interest Purchase Agreement dated September 30, 2013 (the “Agreement”) by and between the Company and Raven. The Cimarrona property is subject to an Ecopetrol Association Contract (the “Association Contract”) whereby Ecopetrol S.A. (“Ecopetrol”) receives royalties of 20% of the oil produced. The pipeline is not subject to the Association Contract. In addition to the royalty, according to the Association Contract, Ecopetrol may, for no consideration, become a 50% partner, once an audit of revenues and expenses indicate that the partners in the Association Contract have received a 200% reimbursement of all historical costs to develop and operate the Guaduas field. If such an audit determines that the specified reimbursement of historical costs occurred prior to September 30, 2013, the Company is required to reimburse Raven for any amounts due to Ecopetrol from Cimarrona LLC which relate to the period prior to that date. The Company believes its maximum exposure is 50% of Cimarrona LLC’s oil revenues for the nine months ended September 30, 2013, or $729,308. The Company has not recorded any provision for this matter, as it is not possible to estimate the potential liability, if any.

F-12

8. MAJOR CUSTOMERS

During ~~the~~ the three and six months ended ~~March~~June 3130, 2015 and 2014, the Company had the following customers who accounted for all of its sales:

	Three Months Ended March 31, 2015					Three Months Ended March 31, 2014
	Three Months Ended June 30, 2015					Three Months Ended June 30, 2014
	Amount		% of Total			Amount		% of Total
Phillips 66	$	21,~~058~~293,~~449~~771		7061.73	%	$	-16,690		0.07	%
Slawson		-		0.0	%		1,917,664		72.7	%
Stephens		519,874		24.6	%		161,627		6.5	%
Stephens		453,906		15.6	%		171,764		6.5	%
Energy Financial		150,527		7.1	%		-		0.0	%
Energy Financial		255,685		8.8	%		-		0.0	%
Devon		107,306		5.1	%		492,857		19.9	%
Devon		119,102		4.1	%		543,469		20.6	%
Other		39,571		1.9	%		169,272		6.8	%
Other		23,139		0.8	%		4,518		0.2	%
Slawson		-		0.0	%		1,638,250		66.1	%
Total	$	2,~~910~~111,~~281~~049		100.0	%	$	2,~~637~~478,~~415~~696		100.0	%

	Six Months Ended June 30, 2015					Six Months Ended June 30, 2014
	Amount		% of Total			Amount		% of Total
Phillips 66	$	3,352,220		66.8	%	$	16,690		0.3	%
Stephens		973,780		19.4	%		333,391		6.5	%
Energy Financial		406,212		8.1	%		-		0.0	%
Devon		226,408		4.5	%		1,036,326		20.3	%
Other		62,709		1.2	%		173,790		3.4	%
Slawson		-		0.0	%		3,555,914		69.5	%
Total	$	5,021,329		100.0	%	$	5,116,111		100.0	%

In September 2014, Slawson sold its interests in its oil and gas properties in Logan County, Oklahoma to Stephens.

9. LIABILITY FOR ASSET RETIREMENT OBLIGATIONS

The Company recognizes a liability at discounted fair value for the future retirement of tangible long-lived assets and associated assets retirement cost associated with the petroleum and natural gas properties. The fair value of the liability is capitalized as part of the cost of the related asset and amortized to expense over its useful life. The liability accretes until the date of expected settlement of the retirement obligations. The related accretion expense is recognized in the statement of operations. The provision will be revised for the effect of any changes to timing related to cash flow or undiscounted abandonment costs. Actual expenditures incurred for the purpose of site reclamation are charged to the asset retirement obligations (“AROs”) to the extent that the liability exists on the balance sheet. The Company recognizes a liability at discounted fair value for the future retirement of tangible long-lived assets and associated assets retirement cost associated with the petroleum and natural gas properties. The fair value of the liability is capitalized as part of the cost of the related asset and amortized to expense over its useful life. The liability accretes until the date of expected settlement of the retirement obligations. The related accretion expense is recognized in the statements of operations. The provision will be revised for the effect of any changes to timing related to cash flow or undiscounted abandonment costs. Actual expenditures incurred for the purpose of site reclamation are charged to the asset retirement obligations (“AROs”) to the extent that the liability exists on the balance sheet. Differences between the actual costs incurred and the fair value of the liability recorded are recognized in income in the period the actual costs are incurred. There are no legally restricted assets for the settlement of AROs. No income tax is applicable to the ARO as of ~~March~~June 3130, 2015 and December 31, 2014, because the Company records a valuation allowance on deductible temporary differences due to the uncertainty of its realization.

~~A reconciliation of the Company’s asset retirement obligations for the three months ended March 31, 2015 is as follows:~~F-13

	Three Months Ended
	March 31, 2015
Beginning balance	$	6,281
Incurred during the period		-
Reversed during the period		-
Additions for new wells		-
Accretion expense		305
Ending balance	$	6,586

A reconciliation of the Company’s asset retirement obligations for the six months ended June 30, 2015 is as follows:

	Six Months Ended
	June 30, 2015
Beginning balance	$	6,281
Incurred during the period		-
Reversed during the period		-
Additions for new wells		-
Accretion expense		614
Ending balance	$	6,895

10. EQUITY

Common Stock and Options

In February 2015, the Company issued 186,934 shares of common stock to two ~~warrantholders~~brokers as a result of a cashless exercise of 193,380 warrants to purchase common stock.

FIn February 2015, we issued a total of 1,100,000 non-13qualified stock options to employees and consultants, exercisable at $0.26 per share, with a Black-Scholes value of $290,860 and an expiration date of February 3, 2018. Variables used in the valuation include (1) discount rate of 0.85%, (2) expected life of 1.5 years for employees and 3 years for the consultants, (3) expected volatility of 220.0% and 221.0% for employees and consultants, respectively, and (4) zero expected dividends. These options were fully vested as of the grant date.

In February 2015, the Company issued a total of 1,100,000 non-qualified stock options to employees and consultants, exercisable at $0.26 per share, with a Black-Scholes value of $290,860 and an expiration date of February 3, 2018. Variables used in the valuation include (1) discount rate of 0.85%, (2) expected life of 1.5 years for employees and 3 years for the consultants, (3) expected volatility of 220.0% and 221.0% for employees and consultants, respectively, and (4) zero expected dividends. These options were fully vested as of the grant date.

In February 2014, the Company initiated a private placement, pursuant to Securities Purchase Agreements between Osage and certain purchasers, with aggregate gross proceeds of approximately $6.7 million. The purchase price of each unit, representing one share of common stock and a warrant to purchase 0.4 shares of common stock at $1.80 per share, was $0.90. The warrants have a term of five years. The placement agent received placement fees of 8%, in cash or warrants or a combination thereof at their election. In total, units representing $6,744,000 were sold in 2014, representing 7,493,339 shares of common stock and warrants to purchase 2,997,333 shares of common stock. The placement agent fees related to these units were cash fees of $338,940 and warrants to purchase 193,380 shares of common stock at $0.01 per share. In addition, the Company incurred legal fees of $10,000 with respect to the private placement in 2014.

On January 2, 2014 ~~the~~we ~~Company~~ issued a total of 550,000 shares to three individuals in connection with amended employment and consulting agreements. Stock based compensation had already been expensed for 150,000 shares. The remaining 400,000 shares vested on January 1, 2015, and as of ~~March~~June 3130, 2014 were valued at $436,000 based on closing prices of $1.00 for 200,000 shares and $1.18 for 200,000 shares. ~~Stock~~were ~~based compensation on the 400,00 shares was~~ expensed over one year in 2014.

On June 5, 2014 we issued a total of 600,000 non-qualified stock options to two employees and a consultant, exercisable at $0.8925 per share, with a Black-Scholes value of $629,714 and an expiration date of June 4, 2024. Variables used in the valuation include (1) discount rate of 0.85%, (2) expected life of 10 years, (3) expected volatility of 220.0% and 219.0% for employees and consultant, respectively, and (4) zero expected dividends. These options were fully vested as of the grant date.

Warrants

In February, 2015, 193,380 warrants were exercised by way of cashless exercise, resulting in the issuance of 186,934 shares of common stock (see above).

During the three months ended March 31, 2014, 200,000 warrants were exercised by a consultant who had previously received the warrants in exchange for services.

~~Total~~On ~~stock-based~~April ~~compensation~~10, ~~expense~~2014 ~~was~~we ~~$290,860~~issued ~~and~~a ~~$109~~warrant to purchase 2,000,000 ~~for~~shares ~~the~~of ~~three~~common ~~months~~stock ~~ended~~to ~~March~~a 31consultant, ~~2015~~exercisable at $1.04 per share, with a Black-Scholes value of $2,184,538 and ~~2014~~an expiration date of April 9, ~~respectively~~2017. ~~All~~Variables used in the valuation include (1) ~~stock-based~~discount ~~compensation~~rate ~~expense~~of is0.81%, ~~included~~(2) inexpected ~~general~~life of 3 years, (3) expected volatility of 223.0% and ~~administrative~~(4) ~~expenses~~zero inexpected ~~the~~dividends. ~~accompanying~~This warrant ~~unaudited~~was ~~financial~~fully ~~statements~~vested as of the grant date.

Total stock-based compensation expense was $0 and $2,923,252 for the three months ended June 30, 2015 and 2014, respectively, and $290,860 and $3,032,252 for the six months ended June 30, 2015 and 2014, respectively. All stock-based compensation expense is included in general and administrative expenses in the accompanying unaudited financial statements.

F-14

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

This report contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 that include, among others, statements of: expectations, anticipations, beliefs, estimations, projections, and other similar matters that are not historical facts, including such matters as: future capital requirements, development and exploration expenditures (including the amount and nature thereof), drilling of wells, reserve estimates (including estimates of future net revenues associated with such reserves and the present value of such future net revenues), future production of oil and gas, repayment of debt, business strategies, and expansion and growth of business operations. These statements are based on certain assumptions and analyses made by our management in light of past experience and perception of: historical trends, current conditions, expected future developments, and other factors that our management believes are appropriate under the circumstances. We caution the reader that these forward-looking statements are subject to risks and uncertainties, including those associated with the financial environment, the regulatory environment, and trend projections, that could cause actual events or results to differ materially from those expressed or implied by the statements. Such risks and uncertainties include those risks and uncertainties identified below. Significant factors that could prevent us from achieving our stated goals include: declines in the market prices for oil and gas, adverse changes in the regulatory environment affecting us, the inherent risks involved in the evaluation of properties targeted for acquisition, our dependence on key personnel, the availability of capital resources at terms acceptable to us, the uncertainty of estimates of proved reserves and future net cash flows, the risk and related cost of replacing produced reserves, the high risk in exploratory drilling and competition. You should consider the cautionary statements contained or referred to in this report in connection with any subsequent written or oral forward-looking statements that may be issued. We undertake no obligation to release publicly any revisions to any forward-looking statement to reflect events or circumstances after the date hereof or to reflect the occurrence of unanticipated events.

In addition to the other information set forth in this report, you should carefully consider the factors discussed in Part I, “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2014, which could materially affect our business, financial conditions or future results. The risks described in our Annual Report on Form 10-K are not the only risks facing the Company. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition and/or operating results.

On April 8, 2008, we entered into a Membership Interest Purchase Agreement (the “Purchase Agreement”) with Sunstone Corporation (“Sunstone”) pursuant to which we acquired from Sunstone 100% of the membership interests in Cimarrona Limited Liability Company, an Oklahoma limited liability company (“Cimarrona LLC”). Cimarrona LLC owns a 9.4% interest in certain oil and gas assets in the Guaduas field, located in the Dindal and Rio Seco Blocks that consist of 21 wells, of which seven are currently producing, that covers 30,665 acres in the Middle Magdalena Valley in Colombia as well as a pipeline with a current capacity of approximately 40,000 barrels of oil per day. The Purchase Agreement was effective as of April 1, 2008. The Cimarrona property is subject to an Ecopetrol Association Contract (the “Association Contract”) whereby we pay Ecopetrol S.A. (“Ecopetrol”) royalties of 20% of the oil produced. The pipeline is not subject to the Association Contract. The royalty amount for the Cimarrona property is paid in oil. The property and the pipeline are both operated by Pacific, which owns 90.6% of the Guaduas field. Pipeline revenues generated from the Cimarrona property primarily relate to transportation costs charged to third party oil producers, including Pacific.

On October 7, 2013, the Company completed the sale of 100% of the membership interests in Cimarrona LLC to Raven Pipeline Company, LLC (“Raven”), pursuant to a Membership Interest Purchase Agreement (the “Agreement”) dated September 30, 2013 by and between the Company and Raven. Accordingly, the Company will not recognize any revenues or expenses for Cimarrona LLC from October 1, 2013. The sales price consisted of cash of $6,550,000 exclusive of escrow, less settlement of debt of Cimarrona LLC of approximately $250,000. Pursuant to the Agreement, the Company also recognized a working capital adjustment of $422,955 and recognized a gain on disposal of discontinued operations of $4,873,660, both in the year ended December 31, 2013. On August 31, 2014 the Company and Raven entered into a settlement agreement, due to numerous uncertainties, whereby the escrow was released to Raven and whereby no additional cash is payable by Raven to the Company.

In 2010, we began to acquire oil and gas leases in Logan County, Oklahoma targeting the Mississippian formation. The Mississippian formation is located on the Anadarko Shelf in northern Oklahoma and south-central Kansas. The top of this expansive carbonate hydrocarbon system is encountered between 4,000 and 6,000 feet and lies stratigraphically between the Pennsylvanian-aged Morrow Sand and the Devonian-aged Woodford Shale formations. The Mississippian formation may reach 600 feet in gross thickness and the targeted porosity zone is between 50 and 300 feet in thickness. The formation’s geology is well understood as a result of the thousands of vertical wells drilled and produced there since the 1940s. Beginning in 2007, the application of horizontal cased-hole drilling and multi-stage hydraulic fracturing treatments have demonstrated the potential for extracting significant additional quantities of oil and natural gas from the formation.

The Woodford Shale is a major energy resource with the potential for significant unconventional oil and gas production. The Woodford is a Devonian aged, highly carboniferous black shale that has sourced the vast majority of migratable hydrocarbons in Oklahoma and Kansas. The known inefficacies of hydrocarbon expulsion is the primary reason why source rocks like the Woodford retain large volumes of oil and gas. Currently, there are more than 1,500 producing horizontal Woodford wells in Oklahoma. This source rock underlies all of our Mississippian acreage.

On April 21, 2011, the Company entered into a participation agreement (“Participation Agreement”) with Slawson and U.S. Energy Development Corporation (“USE,” Slawson and USE, together, the “Parties”). Pursuant to the terms of the Participation Agreement, Slawson and USE acquired 45% and 30% respectively, of our 10,000 acre Nemaha Ridge prospect in Logan County, Oklahoma for $4,875,000. In addition, the Parties carried Osage for 7.5% of the cost of the first three horizontal Mississippian wells, which means that for the first three horizontal Mississippian wells, the Company provided up to 17.5% of the total well costs. After the first three wells, the Company was responsible for up to 25% of the total well costs. Revenue from wells drilled pursuant to the Participation Agreement, after royalty and third party acreage interest payments, was allocated 45% to Slawson, 30% to USE and 25% to Osage. Slawson was the operator of all wells in the Nemaha Ridge prospect in sections where the Parties’ acreage controlled the section. In sections where the Parties’ acreage did not control the section, we may elect to participate in wells operated by others.

Under the Partition Agreement and effective as of September 1, 2013, Slawson agreed to assign all of its rights, title and interest in and to the oil and gas leases and force-pooled acreage which are part of the Nemaha Ridge Project within certain sections to Osage and Osage agreed to assign all of its rights, title and interest in and to the oil and gas leases and force-pooled acreage which are part of the Nemaha Ridge Project within certain sections to the Slawson Exploration Group, such that the net acreage controlled by the parties would remain substantially unchanged, but that the acreage controlled by each of the parties in undeveloped sections would be located in sections where the other party did not control acreage. The parties also agreed that the Participation Agreement would terminate as to all lands within the Nemaha Ridge Project except for lands within sections already developed by the parties which shall continue to be controlled by the Participation Agreement.

In September 2014, Slawson sold its interests in its oil and gas properties in Logan County, Oklahoma to Stephens.

In 2011, the Company began to acquire leases in Pawnee County, Oklahoma, targeting the Mississippian formation. In July 2011, we purchased from B&W Exploration, Inc. (“B&W”) the Pawnee County prospect targeting the Mississippian, for $8,500. In addition, B&W is also entitled to an overriding royalty interest on the leases acquired and a 12.5% carry on the first $200,000 of lease bonus paid in the form of an assignment of 12.5% of the leases acquired. Subsequently, B&W shall have an option to purchase a 12.5% share of leasehold acquired on a heads-up basis. As of ~~March~~June 3130, 2015, the Company had 2,~~886~~113 net acres (3,~~784~~491 gross) leased in Pawnee County.

AtOn ~~March~~April 3127, ~~2015~~2012, we ~~have~~entered ~~leased~~into a $10,000,000 senior secured Note Purchase Agreement with Apollo Investment Corporation. On April 5, 2013 we amended this agreement, increasing the facility to $20,000,000 and on April 3, 2014 we further amended this agreement, increasing the facility to $30,000,000, extending the term of the facility by one year, reducing the interest rate from Libor plus 15% to Libor plus 11% and agreeing to modify the covenants to reflect the transition from participant to operator. On April 7,~~653~~ ~~net~~2014, ~~(50~~we drew down an additional $5 million,~~641~~ ~~gross)~~bringing ~~acres~~total ~~across~~borrowings ~~three~~under ~~counties~~the Note Purchase Agreement to $25 million. We are in ~~Oklahoma~~discussions with Apollo Investment Corporation with respect to non-compliance with certain covenants and with respect to negative trends in oil prices which have diminished Apollo Investment Corporation’s security interest in our reserves. Because we are not in compliance with certain existing covenants and because the notes mature on April 27, 2016, we have classified the Note Purchase Agreement obligations as ~~follows:~~current in the accompanying financial statements.

	Gross	Osage Net
Logan - non-operated	31,754	4,854
Logan - Osage	7,601	4,876
Coal	7,502	3,037
Pawnee	3,784	2,886
	50,641	15,653

The Company has an accumulated deficit of $39,486,653 and a working capital deficit of $36,128,717 as of March 31, 2015. As of March 31, 2015, as a result of production delays and general decline in prevailing oil prices, the Company was not able to operate profitably and was not in compliance with certain covenants under the senior secured Note Purchase Agreement. Without additional financing, the Company may not be able to fully implement its operating plan. These factors raise substantial doubt about the Company’s ability to continue as a going concern. Substantial portions of the losses are attributable to impairment charges, stock-based compensation, professional fees and interest expense. Negative trends in oil prices since the third quarter of 2014 have impacted our operating margins significantly and led to an impairment of our oil and gas properties as of December 31, 2014.

Management of the Company has undertaken steps as part of a plan to improve operations with the goal of sustaining our operations for the next 12 months and beyond. These steps include (a) becoming an operator of our own wells, (b) participating in drilling of wells in Logan County, Oklahoma, (c) controlling overhead and expenses, (d) selling parts of our existing operations, and (e) raising additional equity and/or debt.

On April 27, 2012, we entered into a $10,000,000 senior secured note purchase agreement with Apollo Investment Corporation. On April 5, 2013 we amended this agreement, increasing the facility to $20,000,000 and on April 3, 2014 we further amended this agreement, increasing the facility to $30,000,000, extending the term of the facility by one year, reducing the interest rate from Libor plus 15% to Libor plus 11% and agreeing to modify the covenants to reflect the transition from participant to operator. On April 7, 2014, we drew down an additional $5 million, bringing total borrowings under the Note Purchase Agreement to $25 million. We are in discussions with respect to new covenants to reflect becoming an operator of our own wells and with respect to negative trends in oil prices which have diminished Apollo Investment Corporation’s security interest in our reserves. Existing covenants, some of which we are not in compliance with, remain in effect until the new covenants are agreed upon. Because we are not in compliance with certain existing covenants, we have classified the Note Purchase Agreement obligations as current in the accompanying financial statements. There is no assurance that new terms will be agreed to.

At June 30, 2015, we have leased 14,381 net (52,866 gross) acres across three counties in Oklahoma as follows:

	Gross		Osage Net
Logan - non-operated		34,467		4,787
Logan - Osage		7,602		4,765
Coal		7,306		2,716
Pawnee		3,491		2,113
		52,866		14,381

The Company has an accumulated deficit of $41,402,948 and a working capital deficit of $36,851,307 as of June 30, 2015. As of June 30, 2015, as a result of production delays and prevailing oil prices, the Company was not in compliance with certain covenants under the senior secured Note Purchase Agreement. These factors raise substantial doubt about the Company’s ability to continue as a going concern. Substantial portions of the losses are attributable to impairment charges, stock-based compensation, professional fees and interest expense. Negative trends in oil prices since the third quarter of 2014 have impacted our operating margins significantly and led to an impairment of our oil & gas properties as of December 31, 2014.

Management of the Company has undertaken steps as part of a plan to improve operations with the goal of sustaining our operations for the next 12 months and beyond. These steps include (i) seeking potential merger and combination opportunities, (ii) attempting to refinance our current debt with some combination of new debt and equity, and (iii) considering the potential acquisition of oil and gas properties for equity; all in an effort to stabilize the Company and provide an increased base of operating cash flow.

We are currently in discussions with Apollo Investment Corporation with respect to our covenant violations. However, in the event an event of default is declared and continues under the Note Purchase Agreement, the lender can take certain actions, including demanding immediate repayment of all amounts then outstanding or initiating foreclosure proceedings against us. As the Note Purchase Agreement is secured by substantially all of our assets, there is a risk that if the lender were to request the immediate repayment of the amounts outstanding and we did not have, and could not timely raise, funds to repay such obligations, that the lender (or where applicable, its agent) could foreclose on our assets which could cause us to significantly curtail or cease operations. If amounts outstanding under such Note Purchase Agreement were to be accelerated in the event of the occurrence of an event of default under the Note Purchase Agreement or the continuation thereof, our assets might not be sufficient to repay in full that indebtedness and our other indebtedness and we may not be able to raise funds from alternative sources to repay such obligations on favorable terms, on a timely basis, or at all. As such, the value of our securities may decline in value or become worthless in the event our lender accelerates the repayment of our outstanding obligations. Additionally, such defaults may harm our credit rating and our ability to obtain additional financing on acceptable terms.

The Company’s operating plans require additional funds which may take the form of debt or equity financings. The Company’s ability to continue as a going concern is in substantial doubt and is dependent upon achieving profitable operations and obtaining additional financing. There is no assurance additional funds will be available on acceptable terms or at all. In the event we are unable to continue as a going concern, we may elect or be required to seek protection from our creditors by filing a voluntary petition in bankruptcy or may be subject to an involuntary petition in bankruptcy.

Results of Operations

Three Months ended ~~March~~June 3130, 2015 compared to Three Months ended ~~March~~June 3130, 2014

Our total revenues for the three months ended ~~March~~June 3130, 2015 and 2014 comprised the following:

	2015					2014					Change
	Amount		Percentage			Amount		Percentage			Amount			Percentage
Revenues
Oil sales	$	21,~~463~~760,~~828~~497		8483.74	%	$	21,~~132~~895,~~817~~201		8076.95	%	$	~~331~~(134,~~011~~704	)		15-7.51	%
Natural gas and natural gas liquid sales		~~446~~350,~~452~~552		1516.36	%		~~504~~583,~~598~~495		1923.15	%		(58232,~~146~~943	)		-1139.59	%
Total revenues	$	2,~~910~~111,~~280~~049		100.0	%	$	2,~~637~~478,~~415~~696		100.0	%	$	~~272~~(367,~~865~~647	)		10-14.38	%

Oil Sales

Oil sales were $21,~~463~~760,~~828~~497, in the three months ended ~~March~~June 3130, 2015, ana ~~increase~~decrease of $~~331~~134,~~011~~704, or 157.51%, compared to $21,~~132~~895,~~817~~201 in ~~the~~ the prior year comparable period. The ~~increase~~decrease in oil sales is due to ~~additional~~a ~~wells~~reduction in ~~production~~the inprice ~~Logan~~achieved ~~County,~~only ~~Oklahoma, significantly~~partially offset by aadditional wells ~~reduction~~in production in ~~the~~Logan ~~price~~County, ~~achieved~~Oklahoma. We sold 5232,~~113~~548 barrels (“BBLs”) in 2015 at an average gross price of $4753.2803 per BBL, compared to 2117,~~427~~591 BBLs at an average price of $97102.1656 in the 2014 period.

Natural Gas and Natural Gas Liquids Sales

Natural gas and natural gas liquids sales were $~~446~~350,~~452~~552 for the quarter ended ~~March~~June 3130, 2015 compared to $~~504~~583,~~598~~495 in the prior year comparable period, aan decrease of $58232,~~146~~943 or 1139.59%. All of our natural gas sales are from the well production in Logan County, Oklahoma. ~~Natural~~ Natural gas production is measured in a 1,000 cubic foot unit referred to as a “Mcf.” and natural gas liquid production is is measured in BBLs. We sold 6587,~~401~~034 Mcf of natural gas at an average ~~price~~ of $21.8447 per Mcf in 2015 compared to 7696,~~967~~410 Mcf at $54.3156 per Mcf in 2014. The price achieved per BBL for 1615,~~988~~267 BBLs of natural gas liquids in 2015 was $1514.3113 compared to $2932.3539 for 14,~~731~~769 BBLs in 2014. Certain natural gas and natural gas liquid sales were reported to us by Slawson as natural gas sales in 2014 and by Stephens as natural gas liquid sales in 2015 which impacts the period over period comparison.

Total Revenues

Total revenues were $2,~~910~~111,~~280~~049, ana ~~increase~~decrease of $~~272~~367,~~865~~647, or 1014.38% for the three months ended ~~March~~June 3130, 2015 compared to $2,~~637~~478,~~415~~696 for the prior year comparable period. Oil sales accounted for 8483.74% and 8076.95% of total revenues in the 2015 and 2014 periods, respectively.

Production

For the three months ended ~~March~~June 3130, 2015 and 2014, our production was as follows:

	2015		2014			~~2014~~Increase/(Decrease)						~~Increase/(Decrease)~~
Oil Production:	Net Barrels		% of Total			Net Barrels			% of Total			Barrels			%
	Net Barrels		Net Barrels			Barrels			%
United States		53,467		100.0	%		22,330			100.0	%		31,137			139.4	%
Oil Production:		33,199		17,918			15,281			85.3	%
Natural Gas Production:		Net Mcf		% of Total			Net Mcf			% of Total			Mcf			%
	Net Mcf		Net Mcf			Mcf			%
United States		67,110		100.0	%		77,627			100.0	%		(10,517	)		-13.5	%
Natural Gas Production:		88,775		96,410			(7,635	)		-7.9	%
Natural Gas Liquid Production:		Net Barrels		% of Total			Net Barrels			% of Total			Barrels			%
	Net Barrels		Net Barrels			Barrels			%
United States		17,444		100.0	%		1,796			100.0	%		15,648			871.3	%
Natural Gas Liquid Production:		15,573		4,770			10,803			226.5	%

Oil production, net of royalties, was 5333,~~467~~199 BBLs, an increase of 3115,~~137~~281 BBLs, or ~~139~~85.43%, for the quarter ended ~~March~~June 3130, 2015 compared to 2217,~~330~~918 BBLs for the prior year comparable period, due to production increases as a result of additional wells.

Natural gas production was 6788,~~110~~775 Mcf, a decrease of 107,~~517~~635 Mcf, or 137.59%, for the quarter ended ~~March~~June 3130, 2015, compared to 7796,~~627~~410 Mcf ~~for~~ for the prior year comparable period. Certain natural gas and natural gas liquid production was reported to us by Slawson as natural gas production in 2014 and by Stephens as natural gas liquid production in 2015.

Natural gas liquid production was 1715,~~444~~573 BBLs, an increase of 1510,~~648~~803 BBLs, or ~~871~~226.35%, for the quarter ended ~~March~~June 3130, 2015, compared to 14,~~796~~770 BBLs for the prior year comparable period.

Operating Costs and Expenses

For the three months ended ~~March~~June 3130, 2015 and 2014, our operating expenses were as follows:

	2015						2014						Change
				Percent of						Percent of
	Amount			Sales			Amount			Sales			Amount			Percentage
Operating Expenses
Well operating costs	$	704,922			24.2	%	$	473,142			17.9	%	$	231,780			49.0	%
Well operating expenses	$	511,960			24.3	%	$	390,699			15.8	%	$	121,261			31.0	%
General & administrative espenses		1,195,879			41.1	%		843,952			32.0	%		351,927			41.7	%
General & administrative expenses		891,454			42.2	%		3,643,408			147.0	%		(2,751,954	)		-75.5	%
Depreciation, depletion and accretion		1850,~~025,059~~998			3540.23	%		~~999~~1,~~899~~346,123			3754.93	%		25(495,~~160~~125	)		2-36.58	%
Write off of expired mineral rights leases		141,348			4.9	%		-			-			141,348			n/a
Gain on sale of land interests		-			0.0	%		(77,950	)		-3.1	%		77,950			n/a
Gain on sale of land interests		(197,905	)		-6.8	%		(70,314	)		-2.7	%		(127,591	)		181.5	%
Write off of expired mineral rights leases		562,846			26.7	%		-			0.0	%		562,846			n/a
Total operating expenses	$	2,~~869~~817,~~303~~258			98133.65	%	$	25,~~246~~302,~~679~~280			85213.29	%	$	~~622~~(2,~~624~~485,022	)		27-46.79	%
Operating income	$	40,977			1.4	%	$	390,736			14.8	%	$	(349,759	)		-89.5	%
Operating loss	$	(706,209	)		-33.5	%	$	(2,823,584	)		-113.9	%	$	2,117,375			-75.0	%

Well Operating Costs

Our operating costs were $~~704~~511,~~922~~960 for the three months ended ~~March~~June 3130, 2015 compared to $~~473~~390,~~142~~699 for the three months ended ~~March 31,~~June 30, 2014, due to an increase in operating costs as a result of having 55 wells in production in Logan County at ~~March~~June 3130, 2015. ~~Operating~~ Operating costs as a percentage of total revenues increased to 24.23% in the 2015 period from 1715.98% in the 2014 period, due to lower commodity prices, partially offset by lower average production costs. The average production cost per barrel of oil equivalent (“Production Cost/BOE”) for the three months ended ~~March~~June 3130, 2015 was $8.5505 compared to an average total Production Cost/BOE of $1210.77 08 for the three months ended ~~March~~June 3130, 2014.

General and Administrative Expenses

General and administrative expenses were $1891,~~195,879~~454 for the three months ended ~~March~~June 3130, 2015, compared to $~~843~~3,~~952~~643,408 for the three months ended ~~March~~June 3130, 2014. As a percent of total revenues, general and administrative expenses ~~increased~~decreased to 4142.12% in the 2015 period from 32147.0% in the 2014 period. Stock based compensation for the three months ended ~~March~~June 3130, 2015 was $~~290~~0,~~860,~~ compared to $~~109~~2,~~000~~923,252 in the three months ended ~~March~~June 3130, 2014. Excluding stock based compensation, general and administrative expenses were $~~905~~891,~~019~~454, or 3142.12% of revenues in the three months ended ~~March~~June 3130, 2015, compared to $~~734~~720,~~952~~156, or 2729.91% of revenues in the 2014 period. ~~The~~ The increase of $~~170~~171,~~067~~298 in other general and administrative expenses was primarily due to increased salary, ~~and~~professional fees and insurance expenses.

Depreciation, Depletion and Accretion

Depreciation, depletion and accretion were $1850,~~025,059~~998 for the three months ended ~~March~~June 3130, 2015 and $~~999~~1,~~899~~346,123 for the three months ended ~~March~~June 3130, 2014, ana ~~increase~~decrease of $25495,~~160~~125 or 236.58%. Depletion expense per BOE decreased in ~~the first quarter of~~ 2015 compared to the prior year period, as a result of an impairment charge taken in the fourth quarter of 2014.

Operating ~~Income~~Loss

Operating ~~income~~loss was $40706,~~977~~209 for the three months ended ~~March~~June 3130, 2015 compared to an operating ~~income~~loss of $~~390~~2,~~736~~823,584 for the three months ended June ~~March 31~~30, 2014. The decline in operating ~~income~~loss is as a result of the ~~increase~~decrease in total operating expenses of 2746.79% exceeding ~~the~~ 10the 14.38% revenue ~~growth~~decline.

Interest Expense

Interest expense was $1,~~003~~062,~~213~~120 for the three months ended ~~March~~June 3130, 2015 compared to $1,~~210~~215,~~560~~579 for the three months ended ~~March~~June 3130, 2014, a decrease of $~~207~~153,~~347~~459. The decrease in interest expense during the 2015 period was primarily due to a reduction in ~~deferred financing fees as a result of the one year extension in the term of~~ our ~~Note Purchase Agreement and a reduction in our~~ weighted ~~average~~ average cost of debt partially offset by greater amounts outstanding under our credit facilities. In the three months ended ~~March 31~~June 30, 2015, cash interest expense amounted to $~~812~~871,~~713~~620. The remaining non-cash interest expense of $190,500 represented amortization of deferred financing fees. In the three months ended ~~March~~June 3130, 2014 cash interest expense amounted to $~~862~~1,~~577~~025,080. The remaining non-cash interest expense of $~~347~~190,~~983~~499 consisted of deferred financing fees.

Oil and Gas Derivatives

Oil and gas derivatives reflected an unrealized loss of $~~345~~649,~~907~~807 for the three months ended ~~March~~June 3130, 2015 as a result of marking ~~open~~ open financial derivative instruments to market as of ~~March~~June 3130, 2015 and gains realized on financial derivative instruments settled of $~~549~~501,~~554~~536 during the three months then ended. For the three months ended ~~March~~June 3130, 2014, oil and gas derivatives reflected an unrealized loss of $68243,~~058~~423 as a result of marking open financial derivative instruments to market as of ~~March~~June 3130, 2014 and losses realized on financial derivative instruments settled of $47119,~~669~~572 during the three months then ended.

Provision for Income Taxes

Provision for income taxes was zero for the three months ended ~~March~~June 3130, 2015 and 2014. Due to a history of operating losses, the Company records a full valuation allowance against its net deferred tax assets and therefore recorded no tax provision related to its U.S. operations for the current period.

Net Loss

Net loss was $~~757~~1,~~291~~916,295 in the three months ended ~~March~~June 3130, 2015 compared to a net loss of $~~935~~4,~~127~~397,749 in the prior year comparable period. The decrease in operating ~~income~~loss of $~~349~~2,~~759~~117,375, ~~partially offset by~~ the reduction in interest expense of $~~207~~153,~~347~~459 and the ~~gain~~reduction onin loss on oil and gas derivatives of $~~203~~214,~~647~~724 inrepresent the ~~current year period compared to a loss of $115,727 in the prior year period represent the~~ drivers of the $~~319~~2,~~184~~481,454 decrease in net loss.

Net Loss per Share

Basic and diluted net loss per share was $0.0103 for the three months ended ~~March~~June 3130, 2015 compared to a net loss per share of $0.0208 in ~~the~~ the prior year period.

Six Months ended June 30, 2015 compared to Six Months ended June 30, 2014

Our total revenues for the six months ended June 30, 2015 and 2014 comprised the following:

	2015					2014					Change
	Amount		Percentage			Amount		Percentage			Amount			Percentage
Revenues
Oil sales	$	4,224,325		84.1	%	$	4,028,018		78.7	%	$	196,307			4.9	%
Natural gas and natural gas liquid sales		797,004		15.9	%		1,088,093		21.3	%		(291,089	)		-26.8	%
Total revenues	$	5,021,329		100.0	%	$	5,116,111		100.0	%	$	(94,782	)		-1.9	%

Oil Sales

Oil sales were $4,224,325, in the six months ended June 30, 2015, an increase of $196,307, or 4.9%, compared to $4,028,018 in the prior year comparable period. The increase in oil sales is due to additional wells in production in Logan County, Oklahoma, significantly offset by a reduction in the price achieved. We sold 84,661 barrels in 2015 at an average gross price of $49.90 per BBL, compared to 39,018 BBLs at an average price of $99.43 in the 2014 period.

Natural Gas and Natural Gas Liquids Sales

Natural gas and natural gas liquids sales were $797,004 for the six months ended June 30, 2015 compared to $1,088,093 in prior year comparable period, a decrease of $291,089 or 26.8%. All of our natural gas and natural gas liquid sales are from the well production in Logan County, Oklahoma. We sold 152,436 Mcf of natural gas at an average of $2.07 per Mcf in 2015 compared to 174,037 Mcf at $4.86 per Mcf in 2014. The price achieved per BBL for 32,255 BBLs of natural gas liquids in 2015 was $14.93 compared to $31.58 for 6,500 BBLs in 2014. Certain natural gas and natural gas liquid sales were reported to us by Slawson as natural gas sales in 2014 and by Stephens as natural gas liquid sales in 2015 which impacts the period over period comparison.

Total Revenues

Total revenues were $5,021,329, a decrease of $94,782, or 1.9% for the six months ended June 30, 2015 compared to $5,116,111 for the prior year comparable period. Oil sales accounted for 84.1% and 78.7% of total revenues in the 2015 and 2014 periods, respectively.

Production

For the six months ended June 30, 2015 and 2014, our production was as follows:

	2015		2014		Increase/(Decrease)
	Net Barrels		Net Barrels		Barrels		%
Oil Production:		86,666		40,248		46,418		115.3	%

		Net Mcf				Net Mcf				Mcf				%
Natural Gas Production:			155,885				174,037				(18,152	)			-10.4	%

		Net Barrels				Net Barrels				Barrels				%
Natural Gas Liquid Production:			33,017				6,566				26,451				402.8	%

Oil production, net of royalties, was 86,666 BBLs, an increase of 46,418 BBLs, or 115.3%, for the six months ended June 30, 2015 compared to 40,248 BBLs for the prior year comparable period, due to production increases as a result of additional wells

Natural gas production was 155,885 Mcf, a decrease of 18,152 Mcf, or 10.4%, for the six months ended June 30, 2015, compared to 174,037 Mcf for the prior year comparable period. Certain natural gas and natural gas liquid production was reported to us by Slawson as natural gas production in 2014 and by Stephens as natural gas liquid production in 2015.

Natural gas liquid production was 33,017 BBLs, an increase of 26,451 BBLs, or 402.8%, for the six months ended June 30, 2015, compared to 6,566 BBLs for the prior year comparable period.

Operating Costs and Expenses

For the six months ended June 30, 2015 and 2014, our operating expenses were as follows:

	2015						2014						Change
				Percent of						Percent of
	Amount			Sales			Amount			Sales			Amount			Percentage
Operating Expenses
Well operating expenses	$	1,216,882			24.2	%	$	863,841			16.9	%	$	353,041			40.9	%
General & administrative expenses		2,087,333			41.6	%		4,487,360			87.7	%		(2,400,027	)		-53.5	%
Depreciation, depletion and accretion		1,876,057			37.4	%		2,346,022			45.9	%		(469,965	)		-20.0	%
Gain on sale of land interests		(197,905	)		-3.9	%		(148,264	)		-2.9	%		(49,641	)		33.5	%
Write off of expired mineral rights leases		704,194			14.0	%		-			0.0	%		704,194			n/a
Total operating expenses	$	5,686,561			113.2	%	$	7,548,959			147.6	%	$	(1,862,398	)		-24.7	%

Operating loss	$	(665,232	)		-13.2	%	$	(2,432,848	)		-47.6	%	$	1,767,616			-72.7	%

Well Operating Costs

Our operating costs were $1,216,882 for the six months ended June 30, 2015 compared to $863,841 for the six months ended June 30, 2014, due to an increase in operating costs as a result of having 55 wells in production in Logan County at June 30, 2015. Operating costs as a percentage of total revenues increased to 24.2% in the 2015 period from 16.9% in the 2014 period, due to lower commodity prices, partially offset by lower average production costs. The average Production Cost/BOE for the six months ended June 30, 2015 was $8.34 compared to an average total Production Cost/BOE of $15.89 for the six months ended June 30, 2014.

General and Administrative Expenses

General and administrative expenses were $2,087,333 for the six months ended June 30, 2015, compared to $4,487,360 for the six months ended June 30, 2014. As a percent of total revenues, general and administrative expenses decreased to 41.6% in the 2015 period from 87.7% in the 2014 period. Stock based compensation for the six months ended June 30, 2015 was $290,860, compared to $3,032,252 in the six months ended June 30, 2014. Excluding stock based compensation, general and administrative expenses were $1,796,473, or 35.8% of revenues in the six months ended June 30, 2015, compared to $1,455,108, or 28.4% of revenues in the 2014 period. The increase of $341,365 in other general and administrative expenses was primarily due to increased salary, professional fees and insurance expenses.

Depreciation, Depletion and Accretion

Depreciation, depletion and accretion were $1,876,057 for the six months ended June 30, 2015 and $2,346,022 for the six months ended June 30, 2014, a decrease of $469,965 or 20.0%. Depletion expense per BOE decreased in 2015 compared to the prior year period, as a result of an impairment charge taken in the fourth quarter of 2014.

Operating Loss

Operating loss was $665,232 for the six months ended June 30, 2015 compared to $2,432,848 for the six months ended June 30, 2014. The decline in operating income is as a result of the decrease in total operating expenses of 24.7% exceeding the 1.9% revenue decline.

Interest Expense

Interest expense was $2,065,333 for the six months ended June 30, 2015 compared to $2,426,139 for the six months ended June 30, 2014, a decrease of $360,806. The decrease in interest expense during the 2015 period was primarily due to a reduction in deferred financing fees as a result of the one year extension in the term of our Note Purchase Agreement and a reduction in our weighted average cost of debt offset by greater amounts outstanding under our credit facilities. In the six months ended June 30, 2015, cash interest expense amounted to $1,684,333. The remaining non-cash interest expense of $381,000 represented amortization of deferred financing fees. In the six months ended June 30, 2014 cash interest expense amounted to $1,887,657. The remaining non-cash interest expense of $538,482 consisted of amortization of deferred financing fees.

Oil and Gas Derivatives

Oil and gas derivatives reflected an unrealized loss of $995,714 for the six months ended June 30, 2015 as a result of marking open financial derivative instruments to market as of June 30, 2015 and gains realized on financial derivative instruments settled of $1,051,090 during the six months then ended. For the six months ended June 30, 2014, oil and gas derivatives reflected an unrealized loss of $311,480 as a result of marking open financial derivative instruments to market as of June 30, 2014 and losses realized on financial derivative instruments settled of $167,242 during the six months then ended.

Provision for Income Taxes

Provision for income taxes was zero for the six months ended June 30, 2015 and 2014. Due to a history of operating losses, the Company records a full valuation allowance against its net deferred tax assets and therefore recorded no tax provision related to its U.S. operations for the current period.

Net Loss

Net loss was $2,673,586 in the six months ended June 30, 2015 compared to a net loss of $5,332,876 in the prior year comparable period. The decrease in operating loss of $1,767,616, the reduction in interest expense of $360,806 and the gain on oil and gas derivatives of $55,376 in the current year period compared to a loss of $478,722 in the prior year period represent the drivers of the $2,659,290 decrease in net loss.

Net Loss per Share

Basic and diluted net loss per share was $0.05 the six months ended June 30, 2015 compared to a net loss per share of $0.10 in the prior year period.

Liquidity and Capital Resources

Net cash used inby operating activities totaled $34,~~145~~716,~~967~~987 for the ~~three~~six months ended ~~March~~June 3130, 2015, compared to $35,~~655~~088,~~826~~031 provided by by operations for the ~~three~~six months ended ~~March~~June 3130, 2014. The major components of net cash used inby operating activities for the ~~three~~ ~~months~~six months ended ~~March~~June 3130, 2015 included a decrease in accounts payable and accrued expenses of $78,~~509~~089,~~505,~~551 ~~partially offset by an increase in revenue~~ and ~~royalties~~the ~~payable~~net loss of $2,~~112~~673,~~518~~586, partially offset by a decrease in accounts receivable of $12,~~536~~154,~~015~~647, depletion, depreciation and amortization of $1,~~024~~875,~~754~~443, the unrealized loss on oil and gas derivatives of $~~345~~995,~~907~~714, write off of expired mineral rights leases of $704,194 and stock based compensation of $290,860. The major components of net cash provided by operating activities for the ~~three~~six months ended ~~March~~June 3130, 2014 included non-cash activities which consisted of ~~the~~stock based compensation of $3,032,252, provision for depreciation, depletion and ~~amortization~~accretion of $~~999~~2,~~699~~345,610, amortization of deferred financing costs of $~~347~~538,~~983,~~482 ~~stock based compensation of $109,000~~ and unrealized losses on derivative contracts of $68311,~~058~~480. Other significant components included the $12,~~845~~629,~~500~~212 increase in ~~accounts~~joint ~~payable~~interest ~~and~~billing ~~accrued~~account, ~~expenses~~partially ~~due primarily to our Oklahoma~~offset ~~operations~~by ~~related~~a todecrease ~~well~~in ~~production~~accounts ~~along~~receivable ~~with~~of a$868,372 ~~reduction~~and inby ~~accounts~~the ~~receivable~~net loss of $~~388~~5,~~618~~332,876.

Net cash provided by investing activities totaled $~~533~~264,~~910~~229 for the ~~three~~six months ended ~~March~~June 3130, 2015 and consisted primarily of net ~~proceeds~~ proceeds from the sale of land interests of $769,182, partially offset by investments in oil and gas properties of $~~231~~500,~~250~~931. Net cash used in investing activities totaled $38,~~892~~784,~~720~~106 for the ~~three~~six months ended ~~March~~June 3130, 2014 and consisted primarily of investments in oil and gas properties of $9,115,107 as the Company began drilling and operating its own wells in Logan County, Oklahoma, partially offset by net proceeds from the sale of oil and gas properties of $3339,~~955,953~~165.

Net cash used by financing activities totaled $1424,~~109~~693 for the ~~three~~six months ended ~~March~~June 3130, 2015 and consisted entirely of principal ~~repayments~~ repayments on capital leases. Net cash provided by financing activities totaled $611,~~064~~194,~~699~~878 for the ~~three~~six months ended ~~March~~June 3130, 2014 and consisted primarily of $6,~~066~~306,~~201~~900 in net proceeds from a private placement of securities and $5,000,000 proceeds from the Note Purchase Agreement.

Net operating revenues from our oil production are very sensitive to changes in the price of oil making it very difficult for management to predict whether or not we will be profitable in the future. Negative trends in oil prices since the third quarter of 2014 have impacted our operating margins significantly and led to an impairment of our oil and gas properties as of December 31, 2014.

Management of the Company has undertaken steps as part of a plan to improve operations with the goal of sustaining our operations for the next 12 months and beyond. These steps include (i) seeking potential merger and combination opportunities, (ii) attempting to re-finance our current debt with some combination of new debt and equity, and (iii) considering the potential acquisition of oil and gas properties for equity; all in an effort to stabilize the Company and provide an increased base of operating cash flow.

We conduct no product research and development. Our capital expenditures are directly related to drilling operations and the completion of successful wells. Our level of expenditures in the U.S. is dependent upon successful operations and availability of financing.

We are responsible for any contamination of land we own or lease. However, we carry pollution liability insurance policies, which may limit some potential contamination liabilities as well as claims for reimbursement from third parties.

Effect of Changes in Prices

Changes in prices during the past few years have been a significant factor in the oil and gas (“O&G”) industry. The price received for the oil produced by us fluctuated significantly during the last year. Changes in the price received for our O&G is set by market forces beyond our control as well as governmental intervention. The volatility and uncertainty in O&G prices have made it more difficult for a company like us to increase our O&G asset base and become a significant participant in the O&G industry. We currently sell the majority of our O&G production to Phillips 66, Stephens, Energy Financial and Devon. However, in the event these customers discontinued O&G purchases, we believe we can replace these customers with other customers who would purchase the oil at terms standard in the industry. In our Logan county properties, we sold oil, gas and natural gas liquids at prices ranging from $45.5752 to $5057.9652 per barrel for oil, $2.50 to $3.1115 per Mcf for gas and $13.87 to $1619.7027 per barrel for natural gas liquids in the ~~three~~six months ended ~~March~~June 3130, 2015 and at prices ranging from $9293.8280 to $~~100~~104.3890 per barrel for oil, $3.81 to $6.89 per Mcf for gas and $27.00 to $35.33 per barrel for natural gas liquids in the ~~three~~six months ended ~~March~~June 3130, 2014.

We have material exposure to interest rate changes, as our $25,000,000 secured promissory note carries an interest rate of the London interbank overnight rate (“Libor”) plus 11%, with a Libor floor of 2%.

Oil and Gas Properties

We follow the “successful efforts” method of accounting for our oil and gas exploration and development activities, as set forth in the Statement of Financial Accounting Standards (SFAS) No. 19, as codified by FASB ASC topic 932. Under this method, we initially capitalize expenditures for oil and gas property acquisitions until they are either determined to be successful (capable of commercial production) or unsuccessful. The carrying value of all undeveloped oil and gas properties is evaluated periodically and reduced if such carrying value appears to have been impaired. Leasehold costs relating to successful oil and gas properties remain capitalized while leasehold costs which have been proven unsuccessful are charged to operations in the period the leasehold costs are proven unsuccessful. Costs of carrying and retaining unproved properties are expensed as incurred.

The costs of drilling and equipping development wells are capitalized, whether the wells are successful or unsuccessful. The costs of drilling and equipping exploratory wells are capitalized until they are determined to be either successful or unsuccessful. If the wells are successful, the costs of the wells remain capitalized. If, however, the wells are unsuccessful, the capitalized costs of drilling the wells, net of any salvage value, are charged to operations in the period the wells are determined to be unsuccessful.

8The provision for depreciation and depletion of oil and gas properties is computed on the unit-of-production method. Under this method, we compute the provision by multiplying the total unamortized costs of oil and gas properties including future development, site restoration, and dismantlement abandonment costs, but excluding costs of unproved properties by an overall rate determined by dividing the physical units of oil and gas produced during the period by the total estimated units of proved oil and gas reserves. This calculation is done on a field-by-field basis. As of June 30, 2015 and 2014, our oil and natural gas production operations were conducted in Logan County in the state of Oklahoma. The cost of unevaluated properties not being amortized, to the extent there is such a cost, is assessed quarterly to determine whether the value has been impaired below the capitalized cost. The cost of any impaired property is transferred to the balance of oil and gas properties being depleted. The costs associated with unevaluated properties relate to projects which were undergoing exploration or development activities or in which we intend to commence such activities in the future. We will begin to amortize these costs when proved reserves are established or impairment is determined.

The provision for depreciation and depletion of oil and gas properties is computed on the unit-of-production method. Under this method, we compute the provision by multiplying the total unamortized costs of oil and gas properties including future development, site restoration, and dismantlement abandonment costs, but excluding costs of unproved properties by an overall rate determined by dividing the physical units of oil and gas produced during the period by the total estimated units of proved oil and gas reserves. This calculation is done on a field-by-field basis. As of March 31, 2015 and 2014, our oil and natural gas production operations were conducted in Logan County in the state of Oklahoma. The cost of unevaluated properties not being amortized, to the extent there is such a cost, is assessed quarterly to determine whether the value has been impaired below the capitalized cost. The cost of any impaired property is transferred to the balance of oil and gas properties being depleted. The costs associated with unevaluated properties relate to projects which were undergoing exploration or development activities or in which we intend to commence such activities in the future. We will begin to amortize these costs when proved reserves are established or impairment is determined.

In accordance with SFAS No. 143, “Accounting for Asset Retirement Obligations,” as codified by FASB ASC topic 410, we report a liability for any legal retirement obligations on our oil and gas properties. The asset retirement obligations represent the estimated present value of the amounts expected to be incurred to plug, abandon, and remediate the producing properties at the end of their productive lives, in accordance with state laws, as well as the estimated costs associated with the reclamation of the property surrounding. The Company determines the asset retirement obligations by calculating the present value of estimated cash flows related to the liability. The asset retirement obligations are recorded as a liability at the estimated present value as of the asset’s inception, with an offsetting increase to producing properties. Periodic accretion of the discount related to the estimated liability is recorded as an expense in the statement of operations.

The estimated liability is determined using significant assumptions, including current estimates of plugging and abandonment costs, annual inflation of these costs, the productive lives of wells, and a risk-adjusted interest rate. Changes in any of these assumptions can result in significant revisions to the estimated asset retirement obligations. Revisions to the asset retirement obligations are recorded with an offsetting change to producing properties, resulting in prospective changes to depletion and depreciation expense and accretion of the discount. Because of the subjectivity of assumptions and the relatively long lives of most of the wells, the costs to ultimately retire the Company’s wells may vary significantly from prior estimates.

We review our proved oil and natural gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. We estimate the expected undiscounted future cash flows of our oil and natural gas properties and compare such undiscounted future cash flows to the carrying amount of the oil and natural gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we will adjust the carrying amount of the oil and natural gas properties to fair value. The factors used to determine fair value are subject to our judgment and expertise and include, but are not limited to, actual or proposed recent sales prices of comparable properties, the present value of future cash flows, net of estimated operating and development costs using estimates of proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures, and various discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flows projected. We recorded an impairment charge of $29,858,178 in the fourth quarter of 2014. Because of the uncertainty inherent in these factors, we cannot predict when or if future impairment charges for proved properties will be recorded.

We assess our unproved properties periodically for impairment on a property-by-property basis based on remaining lease terms, drilling results or future plans to develop acreage and record impairment expense for any decline in value.

The assessment of unproved properties to determine any possible impairment requires significant judgment. No impairment was recorded on unproved properties in 2015 or 2014.

Revenue Recognition

We recognize revenue upon transfer of ownership of the product to the customer which occurs when (i) the product is physically received by the customer, (ii) an invoice is generated which evidences an arrangement between the customer and us, (iii) a fixed sales price has been included in such invoice and (iv) collection from such customer is probable.

We recognize sales from our properties using the sales method. Under the sales method, the working interest owners recognize sales of oil and gas regardless of the amount produced for the period. The sales method assumes that any production sold by a working interest owner comes from that party’s share of the total reserves in place. Thus, whatever quantity is sold in any given period is the revenue for that party. No receivables, payables or unearned revenue are recorded unless a working interest owner’s aggregate sales from the property exceed its share of the total reserves in place.

Off-Balance Sheet Arrangements

Our Company has not entered into any transaction, agreement or other contractual arrangement with an entity unconsolidated with us, except as disclosed in our financial statements, under which we have:

●	an obligation under a guarantee contract,


●	a retained or contingent interest in assets transferred to the unconsolidated entity or similar arrangement that serves as credit, liquidity or market risk support to such entity for such assets,


●	any obligation including a contingent obligation, under a contract that would be accounted for as a derivative instrument, or


●	any obligation, including a contingent obligation, arising out of a variable interest in an unconsolidated entity that is held by us and material to us where such entity provides financing, liquidity, market risk or credit risk support to, or engages in leasing, hedging or research and development services with us.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

Our Company is a Smaller Reporting Company. A Smaller Reporting Company is not required to provide the disclosure information required by this item.

Item 4. Controls and Procedures

The Company’s management, including its principal executive officer and principal financial officer, evaluated the effectiveness of the Company’s “disclosure controls and procedures,” as such term is defined in Rule 13a-15(e) promulgated under the Securities Exchange Act of 1934, as amended, (the “Exchange Act”). Based upon their evaluation, the principal executive officer and principal financial ~~officer~~offer concluded that, as of the end of the period covered by this report, the Company’s disclosure controls and procedures were not effective for the purpose of ensuring that the information required to be disclosed in the reports that the Company files or submits under the Exchange Act with the Securities and Exchange Commission (“SEC”) (1) is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and (2) is accumulated and communicated to the Company’s management, including its principal executive and principal financial officers, as appropriate to allow timely decisions regarding required disclosure. Management conducted an assessment of the effectiveness of the Company’s internal control over financial reporting (“ICFR”) as of ~~March~~June 3130, 2015, utilizing a top-down, risk-based approach described in SEC Release No. 34-55929 as suitable for smaller public companies. Based on this assessment, management determined that the Company’s ICFR as of ~~March~~June 3130, 2015 is not effective, and that, as of ~~March~~June 3130, 2015, there were material weaknesses in our ICFR. The material weaknesses identified during management’s assessment was the lack of independent oversight by an audit committee of independent members of the Board of Directors. As defined by the Public Company Accounting Oversight Board Auditing Standard No. 5, a material weakness is a deficiency, or a combination of deficiencies, such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected. Given the difficulty of finding qualified individuals who are willing to serve as independent directors, there has been no change in the audit committee. Our internal control over financial reporting includes policies and procedures that pertain to the maintenance of records that accurately and fairly reflect, in reasonable detail, transactions and dispositions of assets; and provide reasonable assurances that: (1) transactions are recorded as necessary to permit preparation of financial statements in accordance with U.S. GAAP; (2) receipts and expenditures are being made only in accordance with authorizations of management and the directors of the Company; and (3) unauthorized acquisitions, use, or disposition of the Company’s assets that could have a material effect on the Company’s financial statements are prevented or timely detected. All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparations and presentations. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. This quarterly report does not include an attestation report of the Company’s independent registered public accounting firm regarding ICFR. Management’s report was not subject to attestation by the Company’s independent registered public accounting firm pursuant to rules of the SEC.

Except as indicated herein, there were no changes in the Company’s ICFR during the three months ended ~~March~~June 3130, 2015 that have ~~materially~~ materially affected, or are reasonably likely to materially affect, the Company’s ICFR.

PART II – OTHER INFORMATION

Item 1. Legal Proceedings

We have initiated litigation against Stephens with respect to their right to operate 22 wells in which we have a working interest as we contend that we should be the operator. ~~Neither~~Certain ~~the~~vendors ~~Company~~have ~~nor~~recorded ~~any~~Workmen’s Liens against certain properties of ~~its~~which ~~property~~the Company is athe ~~party~~operator, due to, oramounts outstanding to them for work performed at these properties. These Liens have generally been filed due to specific time limitations within which vendors must record the ~~subject~~Liens ~~of,~~under ~~any~~Oklahoma law. Additionally, ~~other~~three ~~material~~vendors ~~pending~~have initiated legal ~~proceedings~~actions ~~other~~against ~~than~~the ~~ordinary,~~Company ~~routine~~over ~~litigation~~non-payment ~~incidental~~of certain amounts due. These actions have been stayed to ~~our~~allow ~~business~~the Company some time to pursue financing alternatives.

Item 1A. Risk Factors

InOur ~~addition~~Company tois ~~the~~a ~~other~~Smaller ~~information~~Reporting ~~set forth in this report, you should carefully consider the factors discussed in Part I, “Item 1A~~Company. ~~Risk~~A ~~Factors”~~Smaller inReporting our Annual Report on Form 10-K for the year ended December 31, 2014, which could materially affect our business, financial conditions or future results. The risks described in our Annual Report on Form 10-K are not the only risks facing the Company. ~~Additional~~is ~~risks and uncertainties~~ not ~~currently~~required ~~known~~ to usprovide orthe ~~that~~risk wefactor ~~currently~~disclosure ~~deem to be immaterial also~~required ~~may~~by ~~materially~~this ~~adversely affect our business, financial condition and/or operating results~~item.

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

In February 2015, the Company issued 186,934 shares of common stock as a result of a cashless exercise of 193,380 warrants to purchase common stock.

The issuance of the securities of the Company in the above transactions was deemed to be exempt from registration under the Securities Act of 1933 by virtue of Section 4(2) thereof or Rule 506 of Regulation D promulgated there under, as transactions by an issuer not involving a public offering. With respect to the transactions listed above, no general solicitation was made by either the Company or any person acting on the Company’s behalf; the securities sold are subject to transfer restrictions; and the certificates for the shares contain an appropriate legend stating that such securities have not been registered under the Securities Act of 1933 and may not be offered or sold absent registration or pursuant to an exemption there from.

Item 3. Default upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable

Item 5. Other Information

(a) ~~None.~~Departure of Directors or Certain Officers

Effective August 14, 2015, Greg L. Franklin, Chief Geologist and Director, no longer serves as an officer or employee of the Company. He continues to serve on the Company’s Board of Directors.

(b) None.

Item 6. Exhibits

See Exhibit Index attached hereto.

1114

SIGNATURES

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

	OSAGE EXPLORATION AND DEVELOPMENT, INC. (Registrant)
Date: May 15, 2015	By:	/s/ Kim Bradford
Date: August 14, 2015	By:	/s/ Kim Bradford
		Kim Bradford
		President and Chief Executive Officer

Date: May 15, 2015	By:	/s/ Norman Dowling
Date: August 14, 2015	By:	/s/ Norman Dowling
		Norman Dowling
		Principal Financial Officer

1215

EXHIBIT INDEX

The following is a list of Exhibits required by Item 601 of Regulation S-K. Except for these exhibits indicated by an asterisk which are filed herewith, the remaining exhibits below are incorporated by reference to the exhibit previously filed by us as indicated.

Exhibit No.		Description

3.1		Articles of Incorporation of Osage Exploration and Development, Inc. (1)

3.2		Bylaws of Osage Exploration and Development, Inc. (2)

31.1		Certification pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, signed by Kim Bradford, President and Chief Executive Officer (Principal Executive Officer)*

31.2		Certification pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, signed by Norman Dowling, Chief Financial Officer (Principal Financial Officer)*

32.1		Certification pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, signed by Kim Bradford, President and Chief Executive Officer (Principal Executive Officer)*

32.2		Certification pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, signed by Norman Dowling, Chief Financial Officer (Principal Financial Officer)*

101.INS		XBRL Instance Document*
101.SCH		XBRL Taxonomy Extension Schema*
101.CAL		XBRL Taxonomy Extension Calculation Linkbase*
101.DEF		XBRL Taxonomy Extension Definition Linkbase*
101.LAB		XBRL Taxonomy Extension Label Linkbase*
101.PRE		XBRL Taxonomy Presentation Linkbase*

	(1)	Incorporated herein by reference to Exhibit 3.1 to the Osage Exploration and Development, Inc. Form 10-SB Amendment No. 1 filed August 27, 2007

	(2)	Incorporated herein by reference to Exhibit 3.2 to the Osage Exploration and Development, Inc. Form 10-SB Amendment No. 1 filed August 27, 2007

		(*) Filed with this Form 10-Q

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