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 September 30, 2014

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

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]

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 November 11, 2014 was 58,098,014.

OSAGE EXPLORATION AND DEVELOPMENT, INC. AND SUBSIDIARIES

TABLE OF CONTENTS

		Page
PART I – FINANCIAL INFORMATION

Item 1.	Financial Statements	F-1

	Consolidated Balance Sheets; September 30, 2014 (unaudited) and December 31, 2013	F-1

	Consolidated Statements of Operations and Other Comprehensive Income (Loss); Three and Nine Months ended September 30, 2014 (unaudited) and 2013 (unaudited)	F-2

	Consolidated Statements of Cash Flows; Nine Months ended September 30, 2014 (unaudited) and 2013 (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	12

Item 4.	Controls and Procedures	13

PART II – OTHER INFORMATION

Item 1.	Legal Proceedings	13

Item 1.A.	Risk Factor	13

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	13

Item 3.	Default upon Senior Securities	14

Item 4.	Mine Safety Disclosures	14

Item 5.	Other Information	14

Item 6.	Exhibits	14

Signatures		15

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

OSAGE EXPLORATION AND DEVELOPMENT, INC. AND SUBSIDIARIES

BALANCE SHEETS

As of September 30, 2014 (unaudited) and December 31, 2013

	September 30, 2014			December 31, 2013
ASSETS

Current assets:
Cash and equivalents	$	8,188,867		$	2,782,643
Accounts receivable		1,412,403			2,769,414
Prepaid expenses and other current assets		169,120			596,742
Deferred financing costs		1,200,142			1,829,124
Total current assets		10,970,532			7,977,923

Property and equipment, at cost:
Oil & gas properties and equipment (successful efforts method)		50,726,019			27,339,460
Other property & equipment		259,025			85,746
		50,985,044			27,425,206
Less: accumulated depletion, depreciation and amortization		(6,578,306	)		(2,683,085	)
		44,406,738			24,742,121

Restricted cash		895,950			908,645
Total assets	$	56,273,220		$	33,628,689

LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:
Accounts payable	$	6,216,223		$	555,784
Joint interest billing		7,512,931			-
Accrued expenses		464,682			117,800
Unrealized losses on oil and gas derivatives		25,518			265,961
Capital lease liability, current portion		42,349			-
Notes payable		25,000,000			20,000,000
Total current liabilities		39,261,703			20,939,545

Unrealized losses on oil and gas derivatives, net of current portion		-			91,606
Capital lease liability, net of current portion		60,524			-
Liability for asset retirement obligations		5,022			3,886
Total liabilities		39,327,249			21,035,037

Commitments and contingencies

Stockholders’ Equity:
Preferred stock, $0.0001 par value, 10,000,000 authorized, none issued and outstanding as of September 30, 2014 or December 31, 2013		-			-
Common stock, $0.0001 par value, 190,000,000 shares authorized; 58,098,014 and 49,854,675 shares issued and outstanding as of September 30, 2014 and December 31, 2013, respectively		5,809			4,985
Additional paid-in capital		26,480,381			16,903,147
Stock purchase notes receivable		(95,000	)		(95,000	)
Accumulated deficit		(9,445,219	)		(4,219,480	)
Total stockholders’ equity		16,945,971			12,593,652
Total liabilities and stockholders’ equity	$	56,273,220		$	33,628,689

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 AND OTHER COMPREHENSIVE INCOME (LOSS)

For the Three and Nine Months ended September 30, 2014 and 2013 (unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013

Operating revenues
Oil revenues	$	2,785,057		$	2,534,162		$	6,813,075		$	4,842,812
Natural gas revenues		543,462			128,134			1,631,555			348,948
Total operating revenues		3,328,519			2,662,296			8,444,630			5,191,760

Operating costs and expenses
Operating costs		588,193			447,325			1,452,034			986,184
General and administrative expenses		821,816			531,056			5,309,176			1,923,899
Depreciation, depletion and accretion		1,549,842			728,486			3,895,864			1,343,498

Total operating costs and expenses		2,959,851			1,706,867			10,657,074			4,253,581

Operating income (loss)		368,668			955,429			(2,212,444	)		938,179

Other income (expenses):
Interest income		2,672			221			7,505			1,361
Interest expense		(1,021,256	)		(1,144,948	)		(3,447,395	)		(3,041,094	)
Gain (loss) on oil and gas derivatives		530,338			(599,832	)		51,616			(636,522	)
Gain on sale of land interests		226,715			-			374,979			-

Income (loss) from continuing operations before income taxes		107,137			(789,130	)		(5,225,739	)		(2,738,076	)
Provision for income taxes		-			-			-			-
Income (loss) from continuing operations		107,137			(789,130	)		(5,225,739	)		(2,738,076	)
Discontinued operations:
Income from discontinued operations net of income taxes		-			590,318			-			2,496,541

Net income (loss)		107,137			(198,812	)		(5,225,739	)		(241,535	)

Other comprehensive income (loss), net of tax:
Foreign currency translation adjustment attributable to discontinued operations		-			1,439			-			24,153

Comprehensive income (loss)	$	107,137		$	(197,373	)	$	(5,225,739	)	$	(217,382	)

Basic income (loss) per share
Continuing operations	$	0.00		$	(0.02	)	$	(0.09	)	$	(0.06	)
Discontinued operations	$	-		$	0.01		$	-		$	0.05

Diluted income (loss) per share
Continuing operations	$	0.00		$	(0.02	)	$	(0.09	)	$	(0.06	)
Discontinued operations	$	-		$	0.01		$	-		$	0.05

Weighted average number of common share and common share equivalents used to compute basic income (loss) per share		58,098,014			49,854,675			55,911,321			49,714,934

Weighted average number of common share and common share equivalents used to compute diluted income (loss) per share		59,770,716			49,854,675			55,911,321			49,714,934

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 Nine Months ended September 30, 2014 and 2013 (unaudited)

	2014			2013
Cash flows from operating activities:
Net loss	$	(5,225,739	)	$	(241,535	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Stock based compensation		3,269,158			420,250
Amortization of deferred financing costs		728,982			955,886
Amortization of debt discount		-			144,901
Gain on sale of land interests		(374,979	)		-
Write off of expired mineral rights leases		31,986			15,283
Accretion of asset retirement obligation		643			4,734
Provision for depletion, depreciation and amortization		3,895,221			1,458,223
Unrealized (gain) loss on oil and gas derivatives		(332,049	)		507,124
Changes in operating assets and liabilities:
Decrease (increase) in accounts receivable		1,357,011			(3,297,666	)
Decrease (increase) in prepaid expenses and other current assets		427,622			(100,364	)
(Decrease) increase in accounts payable and accrued expenses		(70,857	)		5,536,650
Increase in joint interest billing account		7,512,931			-
Net cash provided by operating activities		11,219,930			5,403,486

Cash flows from investing activities:
Investments in oil & gas properties		(17,609,570	)		(17,374,532	)
Investments in non-oil & gas properties		(45,844	)		-
Decrease (increase) in restricted cash		12,695			(168,153	)
Net proceeds from sale of land interests		644,675			14,568
Proceeds from notes receivable		-			6,000
Net cash used in investing activities		(16,998,044	)		(17,522,117	)

Cash flows from financing activities:
Net proceeds from offering of securities		6,744,000			-
Proceeds from secured promissory notes		5,000,000			12,000,000
Proceeds from term loan		-			367,520
Principal payments on term loan		-			(118,205	)
Principal payments on capital leases		(24,562	)		-
Payment of placement fees and expenses		(437,100	)		-
Payment of deferred financing costs		(100,000	)		(100,000	)
Proceeds from exercise of warrants		2,000			3,500
Net cash provided by financing activities		11,184,338			12,152,815

Effect of exchange rate on cash and equivalents		-			25,367

Net increase in cash and equivalents		5,406,224			59,551

Cash and equivalents - beginning of period		2,782,643			486,205

Cash and equivalents - end of period	$	8,188,867		$	545,756

SUPPLEMENTAL CASH FLOW INFORMATION:
Cash payment for interest	$	2,718,413		$	1,961,793
Cash payment for income taxes	$	-			1,624

SUPPLEMENTAL DISCLOSURE OF NON-CASH ACTIVITIES:
Increase in asset retirement obligation	$	493		$	68
Purchase of furniture and fixtures through capital leases	$	127,435		$	-
Oil & gas additions in accounts payable	$	6,078,178		$	-

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

September 30, 2014 and 2013 (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 2013 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

As a result of production delays outside of the Company’s control, the Company was not in compliance with certain covenants as of September 30, 2014, including the minimum production covenant under the senior secured note purchase agreement (see Note 5 - 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 7, 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. The Company also drew down an additional $5,000,000. The Company and the lender are still in discussions about modifications to the covenants and the existing covenants, some of which the Company is not in compliance with, remain in place until new covenants are agreed upon.

In the nine months ended September 30, 2014, the Company raised approximately $6.7 million of gross proceeds in a private placement. (See Note 10 - Equity)

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 operators of our own wells, (b) participating in drilling of wells in Logan County, Oklahoma, (c) controlling overhead and expenses, and (d) raising additional equity and/or debt.

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. There is no assurance additional funds will be available on acceptable terms or at all. This raises substantial doubt about the Company’s ability to continue as a going concern.

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. The results, assets and liabilities of the Company’s former wholly owned subsidiary, Cimarrona, LLC, have been presented as discontinued operations in the consolidated financial statements.

F-4

Use of Estimates

The preparation of financial statements in conformity with 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 materially from those estimates. Management used significant estimates in determining the carrying value of its oil and gas producing assets and the associated depreciation and depletion expense related to sales volumes. The significant estimates include the use of proved oil and gas reserve estimates and the related present value of estimated future net revenues therefrom.

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 2014 or 2013.

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 and nine months ended September 30, 2014 and 2013. 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 in the three and nine months ended September 30, 2014 and four customers in prior year comparable periods.

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.

Deferred financing costs net of accumulated amortization at September 30, 2014 were $1,200,142. Amortization of deferred financing costs was $190,500 and $728,982 for the three and nine months ended September 30, 2014, respectively and $314,462 and $955,886 for the three and nine months ended September 30, 2013, respectively.

Restricted Cash

In connection with the Apollo Note Purchase Agreement, as amended (see Note 5), the Company has classified $812,500 and $850,000, representing three months interest, as restricted cash as of September 30, 2014 and December 31, 2013, respectively. The Company has also pledged $83,450 for certain bonds and sureties at September 30, 2014. Restricted cash at September 30, 2014 was $895,950, compared to $908,645 at December 31, 2013.

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.

Net Income/Loss Per Share

In 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.

The following table shows the computation of basic and diluted net income (loss) per share for the three and nine months ended September 30, 2014 and 2013:

	Three Months Ended September 30,					Nine Months Ended September 30,
	2014		2013			2014			2013
Net income (loss) allocable to continuing operations	$	107,137	$	(789,130	)	$	(5,225,739	)	$	(2,738,076	)
Net income allocable to discontinued operations	$	-	$	590,318		$	-		$	2,496,541

Basic net income (loss) per share
Continuing operations	$	0.00	$	(0.02	)	$	(0.09	)	$	(0.06	)
Discontinued operations	$	-	$	0.01		$	-		$	0.05

Diluted net income (loss) per share
Continuing operations	$	0.00	$	(0.02	)	$	(0.09	)	$	(0.06	)
Discontinued operations	$	-	$	0.01		$	-		$	0.05

Basic and diluted weighted average shares outstanding		58,098,014		49,854,675			55,911,321			49,714,934
Add: Dilutive effect of warrants for common stock		1,672,702		-			-			-
Diluted weighted average shares outstanding		59,770,716		49,854,675			55,911,321			49,714,934

Potential common shares consisted of 7,487,559 and 1,696,843 warrants and options to purchase common stock at September 30, 2014 and 2013, respectively. 5,797,336 of these warrants and options were excluded from the computations for the three months ended September 30, 2014 and all of these warrants and options were excluded from the computations for the nine months ended September 30, 2014 and the three and nine months ended September 30, 2013, as their effect would have been anti-dilutive.

Fair Value of Financial Instruments

As of September 30, 2014 and December 31, 2013, the fair value of cash and equivalents, accounts receivable, notes payable, accounts payable and accrued expenses approximate carrying values because of the short-term maturity of these instruments.

FASB ACS Topic 820, “Fair Value 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.”

F-6

As of September 30, 2014 the Company identified certain derivative financial instruments which required disclosure at fair value on the balance sheet.

The following table presents information for those assets and liabilities requiring disclosure at fair value as of September 30, 2014:

				Total			Fair Value Measurements Using:
	Carrying			Fair			Level 1		Level 2			Level 3
	Amount			Value			Inputs		Inputs			Inputs
September 30, 2014 assets (liabilities):
Commodity derivative liability	$	(25,518	)	$	(25,518	)		-	$	(25,518	)		-

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.

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. The pronouncement is effective for annual and interim reporting periods beginning after December 15, 2016, and is to be applied retrospectively, with early application not permitted.

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.

3. OIL AND GAS PROPERTIES

Oil and gas properties consisted of the following:

	September 30, 2014			December 31, 2013
Properties subject to amortization	$	48,896,901		$	25,551,336
Properties not subject to amortization		1,824,967			1,784,465
Capitalized asset retirement costs		4,151			3,659
Accumulated depreciation and depletion		(6,472,212	)		(2,606,243	)

Oil & gas properties, net	$	44,253,807		$	24,733,217

Depreciation and depletion expense for oil and gas properties totaled $1,548,710 and $3,865,969 in the three and nine months ended September 30, 2014 and 2013, respectively and $723,977 and $1,333,924 in the three and nine months ended September 30, 2013, respectively.

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, 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 Slawson, 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”).

F-7

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 September 30, 2014, Osage operated or has the right to operate approximately 4,356 net acres (6,942 gross), and remains joint-venture or potential joint-venture partners with others in approximately 4,991 net acres (31,292 gross).

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 September 30, 2014, the Company had 3,934 net acres (5,085 gross) leased in Pawnee County.

In 2011, we also began to acquire leases in Coal County, Oklahoma, targeting the Oily Woodford Shale formation. The Oily Woodford Shale formation is located mainly in southeastern Oklahoma in the Arkoma Basin. The Oily 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 September 30, 2014, we had 4,367 net (10,106 gross) acres leased in Coal County.

At September 30, 2014 we have leased 17,648 net (53,425 gross) acres across three counties in Oklahoma as follows:

	Gross		Osage Net
Logan (non operated)		31,292		4,991
Logan - Osage		6,942		4,356
Coal		10,106		4,367
Pawnee		5,085		3,934
		53,425		17,648

4. SEGMENT AND GEOGRAPHICAL INFORMATION

At September 30, 2014, the Company’s continuing 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 originally matured on April 27, 2015, 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.

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 and in April 2014 we paid $100,000 in additional 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 Company paid an amendment fee of $100,000 which is being amortized over the remaining term of the Note Purchase Agreement.

F-8

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 as more fully discussed in Note 11. 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%. During the nine months ended September 30, 2014, we drew down $5,000,000 of additional funds and, as of September 30, 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 and Apollo are negotiating new covenants to the Note Purchase Agreement. Until these negotiations are complete existing covenants, some of which the Company is not in compliance with, remain in place. Accordingly, 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.

Boothbay - Secured Promissory Note

On April 17, 2012, we issued a secured promissory note (“Secured Promissory Note”) to Boothbay Royalty Co., (“Boothbay”) for gross proceeds of $2,500,000. The Secured Promissory Note had a maturity date of April 17, 2014 and bore interest of 18%, payable monthly. In addition, Boothbay received 400,000 shares of common stock for which the relative fair value of $386,545 was recorded as debt discount, a 1.5% overriding royalty on our leases in section 29, township 17 North, range 3 and a 1.7143% overriding royalty on our leases in section 36, township 19 North, range 4 West in Logan County, Oklahoma. The closing price of the Company’s common stock on April 17, 2012 was $1.14. The Secured Promissory Note was secured by a first mortgage (with power of sale), security agreement and financing statement covering a 5% overriding royalty interest, proportionately reduced, in all of the Company’s leases in Logan County, Oklahoma. The Company repaid the Secured Promissory Note in full in December 2013.

In connection with the Note Purchase Agreement, the Company recognized $1,021,056 of interest expense, of which $190,500 was non-cash interest expense and $830,556 was cash interest expense, for the three months ended September 30, 2014. For the nine months ended September 30, 2014, the Company recognized $3,446,976 of interest expense related to this facility, of which $728,982 was non-cash interest expense and $2,717,994 was cash interest expense. In connection with the Note Purchase Agreement and the Secured Promissory Note, the Company recognized $1,144,948 of interest expense, of which $367,948 was non-cash interest expense and $777,000 was cash interest expense, for the three months ended September 30, 2013. For the nine months ended September 30, 2013, the Company recognized $3,041,094 of interest expense related to these facilities, of which $1,100,787 was non-cash interest expense and $1,940,307 was cash interest expense.

F-9

6. DERIVATIVE FINANCIAL INSTRUMENTS

The Company entered into certain derivative financial instruments with respect to a portion of its oil and gas production in the third quarter of 2013. Prior thereto, the Company had not entered into any derivative financial instruments. 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.

As of September 30, 2014, the Company had the following open oil derivative positions. These oil derivatives settle 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.

	Price Collars
	Monthly		Weighted Average		Weighted Average
	Volume		Floor Price		Ceiling Price
Period	(BBLs/m)		($/BBL)		($/BBL)
Q4, 2014	6,000	$	85.00	$	95.00
Q1 - Q2, 2015	6,000	$	80.00	$	93.50

As of September 30, 2014, 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		Weighted Average
	Volume		Floor Price		Ceiling Price
Period	(Btu/m)		($/Btu)		($/Btu)
Q4, 2014		10,000	$	3.75	$	4.40
Q1 - 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.

The following table sets forth the cash settlements and unrealized gains and losses on fair value changes for commodity derivatives for the three and nine months ended September 30, 2014 and 2013.

	Three Months Ended			Nine Months Ended
	September 30, 2014			September 30, 2014
Cash settlements to (by) Company	$	(113,191	)	$	(280,433	)
Unrealized gains (losses) on commodity derivatives		643,529			332,049
Gain (loss) on oil and gas derivatives	$	530,338		$	51,616

	Three Months Ended			Nine Months Ended
	September 30, 2013			September 30, 2013
Cash settlements to (by) Company	$	(129,398	)	$	(129,398	)
Unrealized gains (losses) on commodity derivatives		(470,434	)		(507,124	)
Gain (loss) on oil and gas derivatives	$	(599,832	)	$	(636,522	)

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 its obligations to the Company.

F-10

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 September 30, 2014, 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 $43,989 and $14,595 in the three months ended September 30, 2014 and 2013, respectively and $118,956 and $43,553 for the nine months ended September 30, 2014 and 2013, respectively.

Future minimum commitments under operating leases are as follows as of September 30, 2014:

Year	Amount
2014 (September - December)	$	45,942
2015		184,810
2016		186,098
2017		29,862
	$	446,712

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.

Leased property under capital leases at September 30, 2014 includes:

	September 30, 2014
Furniture and equipment	$	127,436
less: accumulated depreciation		(14,868	)
	$	112,568

F-11

Total depreciation expense under capital leases was $6,372 and $14,868 for the three and nine months ended September 30, 2014 and as of that date the future minimum lease payments under capital leases were as follows:

Year	Amount
2014 (September - December)	$	10,739
2015		42,956
2016		42,956
2017		7,158
		103,809
Less amount representing interest		(936	)
Present value of minimum lease payments	$	102,873

Current maturities	$	42,349
Non-current maturities		60,524
	$	102,873

Legal Proceedings

The Company is not a party to any litigation that has arisen in the normal course of its business or that of its subsidiaries.

Division de Impuestos y Actuanas Nacionales (“DIAN”), the Colombian tax authorities, levies a tax based on the equity value of Cimarrona. In 2010, the Company was notified by DIAN that it owed $883,742 in equity taxes relating to the 2001 and 2003 equity tax years. To compute the value the equity tax is assessed upon, Cimarrona subtracted the cost of its non-producing wells in 2001 and 2003. However, DIAN’s position is that as long as the field is productive, Cimarrona should not have subtracted the cost of the non-producing wells. In May 2011, we settled in full the 2001 equity liability with DIAN. In January 2012, we were informed by DIAN that we had lost our appeal on the 2003 tax issue and we increased the amount attributable to the 2003 tax year by $322,288 as of December 31, 2011 to correspond to the amount DIAN indicated we owed for the 2003 tax year. In January 2013, we successfully concluded negotiations with DIAN with respect to the ultimate liability for the 2003 tax year. DIAN waived certain interest and penalties. We paid the agreed final liability to DIAN in January 2013, and financed the payment with an unsecured Colombian term loan facility in the amount of $367,521. We recognized in discontinued operations the $531,644 benefit of the amnesty in the quarter ended September 30, 2013, upon receipt of official confirmation that the liability is fully settled. We repaid the unsecured Colombian term loan facility in October 2013 in conjunction with the sale of Cimarrona.

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 three and nine months ended September 30, 2014 and 2013, the Company had the following customers who accounted for all of its sales:

	Three Months ended					Three Months ended
	September 30, 2014					September 30, 2013
	Amount		% of Total			Amount		% of Total
Phillips 66	$	1,147,504		34.5	%	$	-		-
Slawson		923,971		27.8	%		2,450,813		92.1	%
Stephens		588,048		17.7	%		173,327		6.5	%
Devon		426,466		12.8	%		32,429		1.2	%
DCP Midstream		163,237		4.9	%		-		-
CMO Energy Partners		76,794		2.3	%		-		-
Sundance		2,499		0.1	%		5,727		0.2	%
Total	$	3,328,519		100.0	%	$	2,662,296		100.0	%

	Nine Months ended					Nine Months ended
	September 30, 2014					September 30, 2013
	Amount		% of Total			Amount		% of Total
Slawson	$	4,479,886		53.1	%	$	4,369,097		84.2	%
Devon		1,462,791		17.3	%		312,867		6.0	%
Phillips 66		1,164,194		13.8	%		-		-
Stephens		921,439		10.9	%		490,457		9.4	%
CMO Energy Partners		230,493		2.7	%		-		-
DCP Midstream		163,237		1.9	%		-		-
Sundance		22,590		0.3	%		19,339		0.4	%
Total	$	8,444,630		100.0	%	$	5,191,760		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 September 30, 2014 and December 31, 2013, because the Company records a valuation allowance on deductible temporary differences due to the uncertainty of its realization.

F-13

A reconciliation of the Company’s asset retirement obligations for the nine months ended September 30, 2014 is as follows:

	Nine Months Ended
	September 30, 2014
Beginning balance	$	3,886
Incurred during the period		-
Reversed during the period		-
Additions for new wells		493
Accretion expense		643
Ending balance	$	5,022

10. EQUITY

Common Stock

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. As of September 30, 2014 units representing $6,744,000 had been sold, representing 7,493,333 shares of common stock and warrants to purchase 2,997,333 shares of common stock. The placement agent fees related to these units as of September 30, 2014 were cash fees of $427,100 and warrants to purchase 196,620 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.

On January 2, 2014 we 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 as discussed below. The remaining 400,000 shares vest on January 1, 2015, were originally valued at $436,000 based on closing prices of $1.00 for 200,000 shares and $1.18 for 200,000 shares. 200,000 of the shares, issued pursuant to a consulting agreement, were revalued from $236,000 to $138,000 as of September 30, 2014, based on a closing price of $0.69. The stock based compensation related to the 400,000 shares is being expensed over one year.

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.

On September 8, 2014 we issued a total of 200,000 non-qualified stock options to a consultant, exercisable at $0.96 per share, with a Black-Scholes value of $173,906 and an expiration date of September 8, 2024. Variables used in the valuation include (1) discount rate of 0.85%, (2) expected life of 10 years, (3) expected volatility of 219.0%, and (4) zero expected dividends. These options were fully vested as of the grant date.

During the three months ended March 31, 2013 we issued 400,000 shares which vested immediately to two employees with a fair value of $364,000, or $0.91 per share. On August 1, 2012, in connection with a three-year employment agreement, we agreed to issue 150,000 shares of common stock at future dates as specified in the agreement. The 150,000 shares were valued at $177,000, or $1.18 per share, and were being expensed over the three years of the employment agreement. We recognized $14,750 of expense related to these shares in the three months ended March 31, 2013. On January 2, 2014, we amended the employment agreement and the vesting of these shares accelerated, and we recognized the unamortized portion of the stock based compensation expense in the fourth quarter of 2013.

Warrants

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.

In addition to the warrants issued pursuant to the private placement discussed above, in April 10, 2014 we issued a warrant to purchase 2,000,000 shares of common stock to a consultant, exercisable at $1.04 per share, with a Black-Scholes value of $2,184,538 and an expiration date of April 9, 2017. Variables used in the valuation include (1) discount rate of 0.81%, (2) expected life of 3 years, (3) expected volatility of 223.0% and (4) zero expected dividends. This warrant was fully vested as of the grant date. This consultant, who acts as project manager for the Company's drilling operations, is president and a shareholder of an entity which holds stock in the Company and participating in certain of the Company's wells.

F-14

Total stock-based compensation expense was $236,906 and $14,750 for the three months ended September 30, 2014 and 2013, respectively, and $3,269,158 and $420,250 for the nine months ended September 30, 2014 and 2013, respectively. All stock-based compensation expense is included in general and administrative expenses in the accompanying unaudited financial statements.

11. DISCONTINUED OPERATIONS

On October 7, 2013, the Company completed the sale of 100% of the membership interests in Cimarrona LLC to Raven, pursuant to the Agreement dated September 30, 2013 by and between the Company and Raven. Cimarrona LLC is the owner of a 9.4% interest in certain oil and gas assets including a pipeline in the Guaduas field, located in the Dindal and Rio Seco Blocks that covers 30,665 acres in the Middle Magdalena Valley in Colombia.

The sales price consisted of cash of $6,550,000 exclusive of escrow, less settlement of debt of Cimarrona LLC of approximately $250,000. $250,000 was to be held in escrow for 12 months to secure any post-Closing purchase price adjustments and any indemnity obligations of the Company pursuant to the Agreement. In addition, so long as the per barrel transportation rate charged with respect to the pipeline was not adjusted prior to March 31, 2014, then Raven was obligated to pay the Company an additional $1,000,000 in cash. Pursuant to the Agreement, the Company also recognized a receivable for a working capital adjustment of $422,955 in other current assets as of December 31, 2013 and recognized a gain on disposal of discontinued operations of $4,873,660 in the year ended December 31, 2013. Raven has reimbursed the Company for the working capital adjustment. 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.

The following table sets forth the results of operations for the discontinued operations for the three and nine months ended September 30, 2013:

	Three Months ended			Nine Months ended
	September 30, 2013			September 30, 2013
Revenues
Oil revenues	$	382,180		$	1,458,616
Pipeline revenues		617,145			1,828,256
Total revenues		999,325			3,286,872

Operating costs and expenses
Operating expenses		328,859			1,007,987
Depreciation, depletion and accretion		19,575			124,193
Equity tax		30,970			(435,988	)
General and administrative		24,592			72,756
Total operating costs and expenses		403,996			768,948

Operating income		595,329			2,517,924

Other income (expenses):
Interest income		19			103
Interest expense		(5,030	)		(21,486	)
Income before income taxes		590,318			2,496,541
Provision for income taxes		-			-

Net income	$	590,318		$	2,496,541

F-15

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.

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 receivable for a working capital adjustment of $422,955 in other current assets as of December 31, 2013 and recognized a gain on disposal of discontinued operations of $4,873,660 in the year ended December 31, 2013.

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 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.

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”).

In 2011, we also began to acquire leases in Coal County, Oklahoma, targeting the Woodford Shale formation. The Wood ford 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 September 30, 2014, we had 4,367 net (10,106 gross) acres leased in Coal County.

At September 30, 2014, we have leased 17,648 net (53,425 gross) acres across three counties in Oklahoma as follows:

	Gross		Osage Net
Logan (non operated)		31,292		4,991
Logan - Osage		6,942		4,356
Coal		10,106		4,367
Pawnee		5,085		3,934
		53,425		17,648

We have accumulated deficits of $9,445,219 (unaudited) at September 30, 2014 and $4,219,480 at December 31, 2013. Substantial portions of the losses are attributable to stock-based compensation, professional fees and interest expense.

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, and (d) 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. Existing covenants, some of which we are not in compliance with, remain in effect until the new covenants are agreed upon.

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. To date, management has not considered this alternative, nor does management view it as a likely occurrence.

Results of Operations

Three Months ended September 30, 2014 compared to Three Months ended September 30, 2013

Our total revenues for the three months ended September 30, 2014 and 2013 comprised the following:

	2014					2013					Change
	Amount		Percentage			Amount		Percentage			Amount		Percentage
Revenues
Oil sales	$	2,785,057		83.7	%	$	2,534,162		95.2	%	$	250,895		9.9	%
Natural gas sales		543,462		16.3	%		128,134		4.8	%		415,328		324.1	%
Total revenues	$	3,328,519		100.0	%	$	2,662,296		100.0	%	$	666,223		25.0	%

Oil Sales

Oil Sales were $2,785,057, an increase of $250,895, or 9.9%, for the three months ended September 30, 2014 compared to $2,534,162 for the three months ended September 30, 2013. Oil sales increased due to an increase in the number of barrels sold partially offset by a reduction in the average price per barrel. We sold 28,015 barrels (“BBLs”) at an average price of $98.92 in the 2014 period, compared to 24,322 BBLs at an average price of $105.03 in the 2013 period.

Natural Gas Sales

Natural gas sales comprise revenues from the sale of natural gas and natural gas liquids. Natural gas sales were $391,735 for the three months ended September 30, 2014 compared to $121,642 for the three months ended September 30, 2013, an increase of $270,093, or 220.0%. We sold 92,925 thousand cubic feet ("Mcf") of natural gas at an average price of $4.22 in the three months ended September 30, 2014, compared to 30,870 Mcf at an average price of $3.40 in the 2013 period. Natural gas liquid sales were $151,727 for the three months ended September 30, 2014 compared to $6,492 in the three months ended June, 2013, an increase of $145,235. We sold 4,672 BBLs of natural gas liquids at an average price of $27.88 in the quarter ended September 30, 2014, compared to 293 BBLs at an average price of $22.64 in the prior year period. Overall, natural gas and natural gas liquid sales increased by 324.1%. All of our natural gas and natural gas liquid sales are from the well production in Logan County, Oklahoma.

Total revenues were $3,328,519 an increase of $666,223, or 25.0% for the three months ended September 30, 2014 compared to $2,662,296 for the three months ended September 30, 2013. Oil sales accounted for 83.7% and 95.2% of total revenues in the 2014 and 2013 periods, respectively.

Production

For the three months ended September 30, 2014 and 2013, our production was as follows:

	2014					2013					Increase/(Decrease)
Oil Production:	Net Barrels		% of Total			Net Barrels		% of Total			Barrels		%
United States		29,003		100.0	%		24,752		100.0	%		4,251		17.2	%

Natural Gas Production:	Net Mcf		% of Total			Net Mcf		% of Total			Mcf		%
United States		94,587		100.0	%		30,870		100.0	%		63,717		206.4	%

Natural Gas Liquid Production:	Net Barrels		% of Total			Net Barrels		% of Total			Barrels		%
United States		4,672		100.0	%		293		100.0	%		4,379		1494.5	%

Oil production, net of royalties, was 29,003 BBLs, an increase of 4,251 BBLs, or 17.2% for the three months ended September 30, 2014 compared to 24,752 BBLs for the three months ended September 30, 2013, due to production increases as a result of new wells coming online.

Natural gas production was 94,587 Mcf for the three months ended September 30, 2014, an increase of 63,717 Mcf, or 206.4% over the production of 30,870 Mcf in the 2013 period. Natural gas liquid production was 4,672 BBLs in the three months ended September 30, 2014, an increase of 4,379 BBLs over the production of 293 in the 2013 period. Gas production began in the first quarter of 2012 in our Logan County properties. We commenced production of natural gas liquids in the second quarter of 2013 at certain wells in Logan County.

Operating Costs and Expenses

For the three months ended September 30, 2014 and 2013, our operating costs and expenses were as follows:

	2014					2013					Change
			Percent of					Percent of
	Amount		Sales			Amount		Sales			Amount			Percentage
Operating costs and expenses
Operating costs	$	588,193		17.7	%	$	447,325		16.8	%	$	140,868			31.5	%
General & administrative expenses		821,816		24.7	%		531,056		19.9	%		290,760			54.8	%
Depreciation, depletion and accretion		1,549,842		46.6	%		728,486		27.4	%		821,356			112.7	%
Total operating costs and expenses	$	2,959,851		88.9	%	$	1,706,867		64.1	%	$	1,252,984			73.4	%

Operating income (loss)	$	368,668		11.1	%	$	955,429		35.9	%	$	(586,761	)		-61.4	%

Operating Costs

Our operating costs were $588,193 for the three months ended September 30, 2014 compared to $447,325 for the three months ended September 30, 2013, due to an increase in operating costs as a result of having 47 wells in production in Logan County at September 30, 2014. Operating costs as a percentage of total revenues increased to 17.7% in the 2014 period from 16.8% in 2013 period, as the percentage increase in revenues was less than the percentage increase in operating costs as new wells came into production. The average production cost per barrel of oil equivalent (“Production Cost/BOE”) for the three months ended September 30, 2014 was $11.90 compared to an average total Production Cost/BOE of $14.94 for the three months ended September 30, 2013.

General and Administrative Expenses

General and administrative expenses were $821,816 for the three months ended September 30, 2014, compared to $531,056 for the three months ended September 30, 2013. As a percent of total revenues, general and administrative expenses increased to 24.7% in the 2014 period from 19.9% in the 2013 period. Stock based compensation for the three months ended September 30, 2014 was $236,906, compared to $14,750 in the three months ended September 30, 2013. Excluding stock based compensation, general and administrative expenses were $584,910, or 17.6% of revenues in the three months ended September 30, 2014, compared to $516,306, or 19.4% of revenues in the 2013 period. The increase of $68,604 in other general and administrative expenses was primarily due to increased salary, legal and professional and insurance expenses.

Depreciation, Depletion and Accretion

Depreciation, depletion and accretion were $1,549,842 for the three months ended September 30, 2014 and $728,486 for the three months ended September 30, 2014, an increase of $821,356 or 112.7%. Our depletion expense will continue to increase to the extent we are successful in our well production in Oklahoma.

Operating Income (Loss)

Operating income was $368,668 for the three months ended September 30, 2014 compared to an operating income of $955,429 for the three months ended September 30, 2014. The decline in operating income is as a result of the increase in total operating expenses of 73.4% exceeding the 25.0% revenue growth.

Interest Expense

Interest expense was $1,021,256 for the three months ended September 30, 2014 compared to $1,144,948 for the three months ended September 30, 2013, a decrease of $123,692. The decrease in interest expense during the 2014 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 three months ended September 30, 2014, cash interest expense amounted to $830,756. The remaining non-cash interest expense of $190,500 represented amortization of deferred financing fees. In the three months ended September 30, 2013, cash interest expense amounted to $770,000. The remaining non-cash interest expense of $367,948 consisted of deferred financing fees of $314,462 and debt discount amortization of $53,486.

Oil and Gas Derivatives

Oil and gas derivatives reflected an unrealized gain of $643,529 for the three months ended September 30, 2014 as a result of marking open financial derivative instruments to market as of September 30, 2014 and losses realized on financial derivative instruments settled of $113,191 during the three months then ended. For the three months ended September 30, 2013 oil and gas derivatives reflected an unrealized loss of $470,434 as a result of marking open financial derivative instruments to market as of September 30, 2013 and losses realized on financial derivative instruments settled of $129,398 during the three months then ended.

Provision for Income Taxes

Provision for income taxes was zero for the three months ended September 30, 2014 and 2013. 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.

Income (loss) from Continuing Operations

Income from continuing operations was $107,137 for the three months ended September 30, 2014 compared to a loss of $789,130 for the three months ended September 30, 2013. The $586,761 decrease in operating income was more than offset by the $1,130,170 improvement to a gain on oil and gas derivatives, the $226,715 gain on sale of land interests and the $123,692 reduction in interest expense in the three months ended September 30, 2014 compared to the prior year period.

Income from Discontinued Operations Net of Income Taxes

Income from discontinued operations net of income taxes was $590,318 in the three months ended September 30, 2013. These operations were disposed of effective September 30, 2013.

Net Income (Loss)

Net Income was $107,137 in the three months ended September 30, 2014 compared to a net loss of $198,812 in 2013. The improvement of $896,267 to income from continuing operations of $107,137 and the reduction of $590,318 in net income from discontinued operations represent the primary drivers.

Foreign Currency Translation Adjustment Attributable to Discontinued Operations

There was no foreign currency gain or loss in the three months ended September 30, 2014 compared to a gain of $1,439 in 2013.

Comprehensive Income (Loss)

Comprehensive income was $107,137 for the three months ended September 30, 2014 compared to comprehensive loss of $197,373 for the three months ended June, 2013. The improvement of $305,949 to net income of $107,137 was the primary contributor.

Income (Loss) per Share

Basic and diluted income per share from continuing operations was $0.00 the three months ended September 30, 2014 compared to a loss per share of $0.02 in the prior year period. There was no income from discontinued operations in the three months ended September 30, 2014, compared to basic and diluted income from discontinued of $0.01 per share in the prior year period.

Nine months ended September 30, 2014 compared to Nine months ended September 30, 2013

Our total revenues for the nine months ended September 30, 2014 and 2013 comprised the following:

	2014					2013					Change
	Amount		Percentage			Amount		Percentage			Amount		Percentage
Revenues
Oil sales	$	6,813,075		80.7	%	$	4,842,812		93.3	%	$	1,970,263		40.7	%
Natural gas sales		1,631,555		19.3	%		348,948		6.7	%		1,282,607		367.6	%
Total revenues	$	8,444,630		100.0	%	$	5,191,760		100.0	%	$	3,252,870		62.7	%

Oil Sales

Oil Sales were $6,813,075, an increase of $1,970,263, or 40.7%, for the nine months ended September 30, 2014 compared to $4,842,812 for the nine months ended September 30, 2013. Oil sales increased due to an increase in the number of barrels sold and an increase in the average price per barrel. We sold 67,032 barrels (“BBLs”) at an average price of $99.26 in the 2014 period, compared to 49,471 BBLs at an average price of $97.87 in the 2013 period.

Natural Gas Sales

Natural gas sales comprise revenues from the sale of natural gas and natural gas liquids. Natural gas sales were $1,289,935 for the nine months ended September 30, 2014 compared to $325,069 for the nine months ended September 30, 2013, an increase of $964,866, or 296.8%. We sold 266,332 Mcf of natural gas at an average price of $4.67 in the nine months ended September 30, 2014, compared to 76,609 Mcf at an average price of $3.97 in the prior year period. Natural gas liquid sales were $341,620 for the nine months ended September 30, 2014 compared to $23,879 in the prior year, an increase of $317,741. We sold 11,173 BBLs of natural gas liquids at an average price of $30.61 in the nine months ended September 30, 2014, compared to 940 BBLs at an average price of $25.71 in the prior year period. Overall, natural gas and natural gas liquid sales increased by 367.6%.

Total revenues were $8,444,630, an increase of $3,252,870, or 62.7% for the nine months ended September 30, 2014 compared to $5,191,760 for the nine months ended September 30, 2013. Oil sales accounted for 80.7% and 93.3% of total revenues in the 2014 and 2013 periods, respectively.

Production

For the nine months ended September 30, 2014 and 2013, our production was as follows:

	2014					2013					Increase/(Decrease)
Oil Production:	Net Barrels		% of Total			Net Barrels		% of Total			Barrels		%
United States		69,251		100.0	%		50,498		100.0	%		18,753		37.1	%

Natural Gas Production:		Net Mcf				% of Total				Net Mcf				% of Total				Mcf				%
United States			268,624				100.0	%			76,609				100.0	%			192,015				250.6	%

Natural Gas Liquid Production:		Net Barrels				% of Total				Net Barrels				% of Total				Barrels				%
United States			11,238				100.0	%			940				100.0	%			10,298				1095.5	%

Oil production, net of royalties, was 69,251 BBLs, an increase of 18,753 BBLs, or 37.1% for the nine months ended September 30, 2014 compared to 50,498 BBLs for the nine months ended September 30, 2013, due to production increases as a result of new wells coming online.

Natural gas production was 268,624 Mcf for the nine months ended September 30, 2014, an increase of 192,015 Mcf, or 250.6% over the production of 76,609 Mcf in the 2013 period. Natural gas liquid production was 11,238 BBLs in the nine months ended September 30, 2014, an increase of 10,298 BBLs over the production of 940 BBLs in the 2013 period. Gas production began in the first quarter of 2012 in our Logan County properties. We commenced production of natural gas liquids in the second quarter of 2013 at certain wells in Logan County.

Operating Costs and Expenses

For the nine months ended September 30, 2014 and 2013, our operating costs and expenses were as follows:

	2014						2013					Change
				Percent of					Percent of
	Amount			Sales			Amount		Sales			Amount			Percentage
Operating costs and expenses
Operating costs	$	1,452,034			17.2	%		986,184		19.0	%	$	465,850			47.2	%
General & administrative expenses		5,309,176			62.9	%		1,923,899		37.1	%		3,385,277			176.0	%
Depreciation, depletion and accretion		3,895,864			46.1	%		1,343,498		25.9	%		2,552,366			190.0	%
Total operating costs and expenses	$	10,657,074			126.2	%	$	4,253,581		81.9	%	$	6,403,493			150.5	%

Operating income (loss)	$	(2,212,444	)		-26.2	%	$	938,179		18.1	%	$	(3,150,623	)		-335.8	%

Operating Costs

Our operating costs were $1,452,034 for the nine months ended September 30, 2014 compared to $986,184 for the nine months ended September 30, 2013, due to an increase in operating costs as a result of having 47 wells in production in Logan County at September 30, 2014. Operating costs as a percentage of total revenues decreased to 17.2% in the 2014 period from 19.0% in 2013 period, as the percentage increase in revenues was greater than the percentage increase in operating costs as new wells came into production. The average Production Cost/BOE for the nine months ended September 30, 2014 was $11.59 compared to an average total Production Cost/BOE of $15.44 for the nine months ended September 30, 2013.

General and Administrative Expenses

General and administrative expenses were $5,309,176 for the nine months ended September 30, 2014, compared to $1,923,899 for the nine months ended September 30, 2013, an increase of $3,385,277, or 176.0%. As a percent of total revenues, general and administrative expenses increased to 62.9% in the 2014 period from 37.1% in the 2013 period. Stock based compensation for the nine months ended September 30, 2014 was $3,269,158, compared to $420,250 in the nine months ended September 30, 2013. Excluding stock based compensation, general and administrative expenses were $2,040,018, or 24.2% of revenues in the three months ended September 30, 2014, compared to $1,503,649, or 29.0% of revenues in the 2013 period. The increase of $536,369 in other general and administrative expenses was primarily due to increased salary, legal and professional and insurance expenses.

Depreciation, Depletion and Accretion

Depreciation, depletion and accretion were $3,895,864 for the nine months ended September 30, 2014 and $1,343,498 for the nine months ended September 30, 2013, an increase of $2,552,366 or 190.0%. Our depletion expense will continue to increase to the extent we are successful in our well production in Oklahoma.

Operating Income (Loss)

Operating loss was $2,212,444 for the nine months ended September 30, 2014 compared to an operating income of $938,179 for the nine months ended September 30, 2013. The increase in operating loss of $3,150,623 from operating income is as a result of the increase in operating costs and expenses of 150.5% exceeding the 62.7% revenue growth.

Interest Expense

Interest expense was $3,447,395 for the nine months ended September 30, 2014 compared to $3,041,094 for the nine months ended September 30, 2013, an increase of $406,301. The increase in interest expense during the 2014 period was primarily due to greater amounts outstanding under our credit facilities offset by a reduction in our weighted average cost of debt and a reduction in deferred financing fees as a result of the one year extension in the term of our Note Purchase Agreement. In the nine months ended September 30, 2014, cash interest expense amounted to $2,718,413. The remaining non-cash interest expense of $728,982 represented amortization of deferred financing fees. In the nine months ended September 30, 2013, cash interest expense amounted to $1,940,297. The remaining non-cash interest expense of $1,100,797 consisted of deferred financing fees of $955,886 and debt discount amortization of $144,901.

Oil and Gas Derivatives

Oil and gas derivatives reflected an unrealized gain of $332,049 for the nine months ended September 30, 2014 as a result of marking open financial derivative instruments to market as of September 30, 2014 and losses realized on financial derivative instruments settled of $280,433 during the nine months then ended. For the nine months ended September 30, 2013 oil and gas derivatives reflected an unrealized loss of $507,124 as a result of marking open financial derivative instruments to market as of September 30, 2013 and losses realized on financial derivative instruments settled of $129,398 during the nine months then ended.

Provision for Income Taxes

Provision for income taxes was zero for the nine months ended September 30, 2014 and 2013. 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.

Loss from Continuing Operations

Loss from continuing operations was $5,225,739 for the nine months ended September 30, 2014 compared to a loss of $2,738,076 for the nine months ended September 30, 2013. The primary contributors were the $3,150,623 increase in operating loss and the $406,301 increase in interest expense, partially offset by the $688,138 improvement in gain on oil and gas derivatives from a loss and the gain on sale of land interests in 2014 of $374,979.

Income from Discontinued Operations Net of Income Taxes

Income from discontinued operations net of income taxes was $2,496,541 in the nine months ended September 30, 2013. These operations were disposed of effective September 30, 2013.

Net Income (Loss)

Net loss was $5,225,739 in the nine months ended September 30, 2014 compared to a net loss of $241,535 in 2013. The increase in loss from continuing operations of $2,487,663 and the reduction of $2,496,541 in net income from discontinued operations represent the drivers of the $4,984,204 increase in net loss.

Foreign Currency Translation Adjustment Attributable to Discontinued Operations

There was no foreign currency gain or loss in the nine months ended September 30, 2014 compared to a gain of $24,153 in 2013.

Comprehensive Income (Loss)

Comprehensive loss was $5,225,739 for the nine months ended September 30, 2014 compared to a comprehensive loss of $217,382 for the nine months ended September 30, 2013. The $4,984,204 increase in net loss was the primary contributor, along with the foreign currency translation gain of $24,153 in the prior year period.

Income (Loss) per Share

Basic and diluted loss per share from continuing operations was $0.09 for the nine months ended September 30, 2014 compared to a basic and diluted loss per share of $0.06 in the prior year period. There was no income from discontinued operations in the nine months ended September 30, 2014, compared to basic and diluted income from discontinued operations of $0.05 per share in the prior year period.

Liquidity and Capital Resources

Net cash provided by operating activities totaled $11,219,930 for the nine months ended September 30, 2014, compared to $5,403,486 for the nine months ended September 30, 2013. The major components of net cash provided by operating activities for the nine months ended September 30, 2014 included non-cash activities which consisted of stock based compensation of $3,269,158, provision for depreciation, depletion and accretion of $3,859,221 and amortization of deferred financing costs of $728,982. Other significant components included the $7,512,931 increase in joint interest billing account and a decrease in accounts receivable of $1,357,011, partially offset by the net loss of $5,225,739. The major components of net cash provided by operating activities for the nine months ended September 30, 2013 included non-cash activities which consisted of stock based compensation of $420,250, provision for depreciation, depletion and accretion of $1,458,223, amortization of deferred financing costs of $955,886 and amortization of debt discount of $144,901. Other components included the $5,536,650 increase in accounts payable and accrued expenses due primarily to our Oklahoma operations related to well production and partially offset by an increase in accounts receivable of $3,297,666.

Net cash used in investing activities totaled $16,998,044 for the nine months ended September 30, 2014 and consisted primarily of investments in oil and gas properties of $17,609,570 as the Company began drilling and operating its own wells in Logan County, Oklahoma, partially offset by net proceeds from the sale of land interests of $644,675. Net cash used in investing activities totaled $17,522,117 for the nine months ended September 30, 2013 and consisted primarily of investments in oil and gas wells of $17,374,532.

Net cash provided by financing activities totaled $11,184,338 for the nine months ended September 30, 2014 and consisted primarily of $6,306,900 in net proceeds from a private placement of securities and $5,000,000 proceeds from the Note Purchase Agreement. Net cash provided by financing activities amounted to $12,152,815 in the nine months ended September 30, 2013, consisting primarily of $12,000,000 proceeds from the Note Purchase Agreement.

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.

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 all of our O&G production to Slawson, Devon, Stephens, CMO Energy Partners, Phillips 66, DCP Midstream and Sundance in the U.S. 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 and gas at prices ranging from $93.66 to $104.90 per barrel and $3.62 to $6.89 per Mcf in the nine months ended September 30, 2014 and at prices ranging from $90.28 to $94.27 per barrel and $3.81 to $6.61 per Mcf in the nine months ended September 30, 2013. We began to sell natural gas liquids in the second quarter of 2013 and we sold natural gas liquids in our Logan county properties at prices ranging from $25.85 to $45.31 per barrel in the nine months ended September 30, 2014 and $25.91 to $28.87 per barrel in the prior year.

We have exposure to changes in interest rates as our Apollo debt facility is tied to the London inter-bank overnight rate.

Oil and Gas Properties

We follow the “successful efforts” method of accounting for our O&G exploration and development activities, as set forth in FASB ASC Topic 932 (“ASC 932”). Under this method, we initially capitalize expenditures for O&G property acquisitions until they are either determined to be successful (capable of commercial production) or unsuccessful. The carrying value of all undeveloped O&G properties is evaluated periodically and reduced if such carrying value appears to have been impaired. Leasehold costs relating to successful O&G 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 expensed in the period the wells are determined to be unsuccessful. We did not record any impairment charges during the nine months ended September 30, 2014 or 2013. The provision for depreciation and depletion of O&G properties is computed on the unit-of-production method. Under this method, we compute the provision by multiplying the total unamortized costs of O&G 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 O&G produced during the period by the total estimated units of proved O&G reserves. This calculation is done on a field-by-field basis. As of September 30, 2014 and 2013 our oil production operations were conducted in the U.S. 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 O&G 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 FASB ASC Topic 410 (“ASC 410”), “Accounting for Asset Retirement Obligations,” we record a liability for any legal retirement obligations on our O&G 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.

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.

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 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 September 30, 2014, 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 September 30, 2014 is not effective, and that, as of September 30, 2014, 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 nine months ended September 30, 2014 that have materially affected, or are reasonably likely to materially affect, the Company’s ICFR.

PART II – OTHER INFORMATION

Item 1. Legal Proceedings

We are not a party to, or the subject of, any material pending legal proceedings other than ordinary, routine litigation incidental to our business.

Item 1A. Risk Factors

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

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

In January 2014, we issued a total of 550,000 shares to three individuals in connection with amended employment and consulting agreements.

In January 2014, 200,000 warrants were exercised by a consultant who had previously received the warrants in exchange for services.

In April 2014, we issued a warrant to purchase 2,000,000 shares of common stock to a consultant, exercisable at $1.04 per share.

In June 2014, we issued a total of 600,000 non-qualified stock options to two employees and a consultant, exercisable at $0.8925 per share.

In September 2014, we issued 200,000 non-qualified stock options to a consultant, exercisable at $0.96 per share.

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.

(b) None.

Item 6. Exhibits

See Exhibit Index attached hereto.

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: November 12, 2014	By:	/s/ Kim Bradford
		Kim Bradford
		President and Chief Executive Officer

Date: November 12, 2014	By:	/s/ Norman Dowling
		Norman Dowling
		Principal Financial Officer

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)

10.33		Settlement Agreement with Raven Pipeline Company dated August 31, 2014*

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

OSAGE EXPLORATION & DEVELOPMENT, INC. 10-Q